10-K

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JONES ENERGY, INC. TABLE OF CONTENTS
Index to Financial Statements

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2015
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to

Commission file number: 001-36006

Jones Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 80-0907968
(I.R.S. Employer
Identification No.)

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(Address of principal executive offices) (Zip Code)

Tel: (512) 328-2953
Registrant's telephone number, including area code

         Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of class	Name of each exchange on which registered
Class A Common Stock, $0.001 par value	New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Exchange Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer ý Non-accelerated filer o
(Do not check if a
smaller reporting company) Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2015 (the last business day of the Registrant's most recently completed second fiscal quarter) based on the closing price of the Class A common stock on the New York Stock Exchange was $272.4 million.

         There were 30,550,907 and 31,273,130 shares of the registrant's Class A and Class B common stock, respectively, outstanding on February 29, 2016.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's definitive proxy statement for the 2016 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year, which we refer to as the Proxy Statement, are incorporated by reference into Part III of this Annual Report on Form 10-K.

JONES ENERGY, INC.
TABLE OF CONTENTS

PART 1
Item 1. Business	3
Item 1A. Risk Factors	30
Item 1B. Unresolved Staff Comments	55
Item 2. Properties	55
Item 3. Legal Proceedings	55
Item 4. Mine Safety Disclosures	55
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	56
Item 6. Selected Financial Data	58
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	63
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	84
Item 8. Financial Statements and Supplementary Data	85
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A. Controls and Procedures	85
Item 9B. Other Information	87
PART III
Item 10. Directors, Executive Officers and Corporate Governance	87
Item 11. Executive Compensation	87
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13. Certain Relationships and Related Transactions, and Director Independence	88
Item 14. Principal Accounting Fees and Services	88
PART IV
Exhibit Index	89
Signatures	93
Financial Statements
Balance Sheets	F-3
Statements of Operations	F-4
Statement of Changes in Stockholders' / Members' Equity	F-5
Statements of Cash Flows	F-6
Notes to the Consolidated Financial Statements	F-7

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Cautionary Statement Regarding Forward-Looking Statements

        The information in this Annual Report on Form 10-K (the "Annual Report"), includes "forward-looking statements." All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words "could," "should," "will," "may," "believe," "anticipate," "intend," "estimate," "expect," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in this report. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events, actions and developments including:

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business strategy;

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estimated current and future net reserves and the present value thereof;

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drilling and completion of wells including our identified drilling locations;

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cash flows and liquidity;

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financial strategy, budget, projections and operating results;

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future prices and change in prices for oil, natural gas and NGLs;

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customers' elections to reject ethane and include it as part of the natural gas stream;

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timing and amount of future production of oil and natural gas;

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availability and cost of drilling, completion and production equipment;

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availability and cost of oilfield labor;

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the amount, nature and timing of capital expenditures, including future development costs;

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ability to fund our 2016 capital expenditure budget;

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availability and terms of capital;

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development results from our identified drilling locations;

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ability to generate returns and pursue opportunities;

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marketing of oil, natural gas and NGLs;

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property acquisitions and dispositions;

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the availability, cost and terms of, and competition for mineral leases and other permits and rights-of-way and our ability to maintain mineral leases;

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costs of developing our properties and conducting other operations;

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general economic conditions, including the levels of supply and demand for oil, natural gas and NGLs, and the commodity price environment;

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competitive conditions in our industry;

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effectiveness and extent of our risk management activities;

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estimates of future potential impairments;

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environmental and endangered species regulations and liabilities;

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counterparty credit risk;

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the extent and effect of any hedging activities engaged in by us;

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the impact of, and changes in, governmental regulation of the oil and natural gas industry, including tax laws and regulations, environmental, health and safety laws and regulations, and laws and regulations with respect to derivatives and hedging activities;

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developments in oil-producing and natural gas-producing countries;

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uncertainty regarding our future operating results;

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weather, including its impact on oil and natural gas demand and weather-related delays on operations;

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technology; and

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plans, objectives, expectations and intentions contained in this report that are not historical.

        We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to, commodity price levels and volatility, inflation, the cost of oil field equipment and services, lack of availability of drilling, completion and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in this report.

        Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

        Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

        All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

        Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

References

        Unless indicated otherwise in this Annual Report or the context requires otherwise, all references to "Jones Energy," the "Company," "our company," "we," "our" and "us" refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC. Jones Energy, Inc. is a holding company whose sole material asset is an equity interest in Jones Energy Holdings, LLC.

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PART 1

Item 1.    Business

Organization

        Jones Energy, Inc. was incorporated pursuant to the laws of the State of Delaware in March 2013 to become a holding company for an investment in Jones Energy Holdings, LLC ("JEH"). As the sole managing member of JEH, Jones Energy, Inc. is responsible for all operational, management and administrative decisions relating to JEH's business and consolidates the financial results of JEH and its subsidiaries.

        Jones Energy, Inc.'s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the pre-IPO owners of JEH and can be exchanged (together with a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. Jones Energy, Inc.'s Class A common stock has been listed on the New York Stock Exchange ("NYSE") under the symbol "JONE" since July 2013.

Overview

        We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family's long history in the oil and gas business, which dates back to the 1920's. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled 827 total wells, including over 650 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct basins in the Texas Panhandle and Oklahoma:

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the Anadarko Basin—targeting the liquids-rich Cleveland, Granite Wash, Tonkawa and Marmaton formations; and

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the Arkoma Basin—targeting the Woodford shale formation.

        We seek to optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we are recognized as one of the lowest cost drilling and completion operators in the Cleveland and Woodford shale formations.

        The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil and natural gas basins in the United States, characterized by multiple producing horizons and extensive well control collected over 100 years of development. We leverage our extensive geologic experience in the basin and seek to identify the most profitable exploration and development opportunities to apply our operational expertise. The formations we target are generally characterized by oil and/or liquids-rich natural gas content, extensive production histories, long-lived reserves, high drilling success rates and attractive initial production rates. We focus on formations in our operating areas that we believe offer significant development and acquisition opportunities and to which we can apply our technical experience and operational excellence to increase proved reserves and production to deliver attractive economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of 2,103 gross identified drilling locations, identifying new

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opportunities within our existing asset base, and actively pursuing organic leasing, strategic acquisitions and joint development agreements. In all of our joint development agreements, we control the drilling and completion of a well, which is the phase during which we can most effectively leverage our operational expertise and cost discipline. Following completion, we may in some cases turn over operatorship to a partner during the production phase of a well. We believe the ceding to us of drilling and completion operatorship in our areas of operation by several large oil and gas companies, including ExxonMobil and BP, reflects their acknowledgement of our low-cost, safe and efficient operations.

        As of December 31, 2015, our total estimated proved reserves were 101.7 MMBoe, of which 58% were classified as proved developed reserves. Approximately 25% of our total estimated proved reserves as of December 31, 2015 consisted of oil, 32% consisted of NGLs, and 43% consisted of natural gas. As of December 31, 2015, our properties included 1,016 gross producing wells. For the three years ended December 31, 2015, we drilled 294 wells, substantially all of which we drilled as operator. The following table presents summary reserve, acreage and production data for each of our core operating areas:

	As of December 31, 2015									Year Ended December 31, 2015
	Estimated Net Proved Reserves					Acreage				Average Daily Net Production
	MMBoe		% Oil and NGLs			Gross Acreage		Net Acreage		MBoe/d		% Oil and NGLs
Cleveland		80.6		63	%		181,353		117,700		18.4		64	%
Woodford		16.3		32	%		12,383		4,418		3.6		31	%
Other		4.8		43	%		34,488		15,259		3.1		40	%
All properties		101.7		57	%		228,224		137,377		25.1		57	%

        The following table presents summary well and drilling location data for each of our key formations for the date indicated:

	As of December 31, 2015
	Producing Wells				Identified Drilling Locations(1)
	Gross		Net		Gross		Net
Cleveland		573		410		711		455
Woodford		152		59		277		45
Other		291		81		1,115		473
All properties		1,016		550		2,103		973

(1)

Our total identified drilling locations include 412 gross locations associated with proved undeveloped reserves as of December 31, 2015. We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and other criteria. See "Business—Development of Proved Undeveloped Reserves" and "Business—Drilling Locations" for more information regarding our proved undeveloped reserves and the processes and criteria through which these drilling locations were identified.

        Our 2015 capital expenditures totaled $200.1 million (excluding the impact of asset retirement costs), of which $173.2 million was utilized to drill and complete operated wells. The Company has established an initial capital budget of $25 million for 2016, a decrease of approximately 87.9% from the $206.4 million incurred for 2015, with the majority of the initial 2016 budget dedicated to capital well workovers and field optimization activities. We will continue to monitor market conditions and

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may spend additional funds for a variety of opportunities which may include redeploying rigs to resume drilling activities or leasing additional acreage. At present, the Company continues to negotiate with vendors regarding service costs and does not plan on resuming its drilling program until well costs create acceptable rates of return at the available commodity prices. Please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources." Assuming current market conditions, we believe we will be able to fund all of our 2016 budgeted capital expenditures with our cash flow from operations. Furthermore, we expect to develop all drilling locations classified as proved undeveloped reserves in the year-end reserve report within five years. We consider projections of future commodity prices when determining our development plan, but many other factors are also considered. Should the commodity price environment or other material factors change significantly from current levels, we will re-evaluate our development plan at that time. If the evaluation results in a shifting of capital expenditures into future periods beyond five years from the initial proved reserve booking, it could potentially lead to a reduction in proved undeveloped reserves.

Business Strategies

        Our goal is to increase shareholder value by managing our capital expenditures and level of activity to maximize returns through commodity price cycles while also evaluating and executing opportunities for growth of reserves, production, and cash flow through potential partnerships, acquisitions, and leasing opportunities. We seek to achieve this goal by executing a combination of the following strategies:

Maintain the Lowest Cost Structure in the Plays Where We Operate.

        Decades of experience in the Midcontinent and emphasis on operational execution and cost control have allowed us to drill and complete wells at significantly lower cost than most other operators and, as a result, to realize compelling economic returns. In the Cleveland, for example, from 2005 to 2014 we reduced our well spud-to-rig release time, which directly affects drilling costs, from 30 days to 23 days, and in 2015 we further reduced that metric to 17 days, down six days from 2014. During that same timeframe, we have more than doubled the lateral lengths of wells we drilled, which directly affects production, from approximately 2,000 feet to approximately 4,500 feet per well. We will continue to apply this expertise while also leveraging our leading position in our focus areas to obtain the best possible pricing from service providers which we expect will further reduce capital costs and ultimately enhance returns. Our cost structure is particularly important in periods of low commodity prices and may give us an advantage over other operators as we compete for acquisitions, leases, and strategic partnerships.

Develop Our Multi-Year Inventory.

        We intend to add production and reserves through the development of our existing drilling inventory, which we believe to be repeatable and low-risk. The Company has a long history in the Midcontinent, having drilled 827 wells in the area since 1988. We believe our historical drilling experience, together with the results of substantial industry activity within our operating areas, reduces the risk and uncertainty associated with drilling horizontal wells in these areas. As of December 31, 2015, we have identified 2,103 gross drilling locations, which gives us many years of development drilling based on our current development plan.

Opportunistically Grow Through Exploration, Acquisitions and Strategic Partnerships.

        As a complement to our development program, we look to execute acquisitions, leases and partnerships where our operating experience can be leveraged. Given the Company's ability to decrease costs and ramp up drilling activity, we seek opportunities that have less PDP reserves and a large

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number of high-quality drilling locations. Since 2009, we have successfully executed four significant acquisitions and several bolt-on acquisitions in our operating areas, for an aggregate purchase price of approximately $900 million.

        We also continue to seek new leasing opportunities to expand our acreage position and complement our existing drilling inventory, as we believe that targeted organic leasing around our existing acreage provides the ability for greater returns due to cost and operating synergies in overlapping areas of operation. In calendar year 2015, we leased over 10,000 net acres.

        Joint development opportunities complement our acquisition strategy by providing a capital efficient and risk-lowering approach to acquiring drilling opportunities. These agreements give us control over the drilling and completion phase of the well, where we can add value by applying our low cost structure. In this regard, we have a history of developed relationships with several large exploration and production companies such as BP, ConocoPhillips, Devon Energy, ExxonMobil, Linn Energy, Vanguard Natural Resources and Samson Resources, in which they have farmed out portions of their basin operations to us. We have drilled over 310 wells in connection with these types of agreements, over 170 of which have been drilled in connection with an active 15-year farm-out and development agreement with ExxonMobil.

Exploit Upside Within Our Existing Assets.

        The stacked reservoirs within our asset base provide exposure to additional upside potential in several emerging resource plays. We have begun assessing the potential of both the Tonkawa and Marmaton formations in the Anadarko Basin. We expect to engage in additional development activity within these plays as commodity prices improve. Based upon our recent assessment, we believe that we have approximately 752 potential drilling locations in the Tonkawa and Marmaton formations that provide us with additional resource potential. Further, our current leasehold position provides longer term potential exposure to other prospective formations found in the Anadarko basin, including the Douglas, Cottage Grove, Cherokee Shale, Atoka Shale, and the Upper, Middle and Lower Morrow formations. In addition, we continue to apply our proven geoscience expertise in the search for new exploration opportunities in the greater Midcontinent region.

Maintain Operational Control.

        We operated substantially all of the wells that we drilled and completed during 2015, allowing us to effectively manage the timing and levels of our development spending, overall well costs and operating expenses. In addition, we expect to operate the drilling and completion phase on approximately 72% of our 2,103 gross identified drilling locations. With over 80% of our acreage held by existing production, we also will not be required to expend significant capital to hold acreage in our portfolio. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.

Focus on Well-Level Returns.

        Our management and technical teams are focused on maximizing well-level returns, which we believe drives shareholder value. In addition to our focus on costs and optimizing drilling and completion techniques, our team maximizes returns by allocating capital to areas with the highest rates of return based on commodity mix. Our drilling inventory comprises oil, natural gas and NGLs, which enables us to adjust our development approach based on prevailing commodity prices. In light of current commodity prices, we will continue to focus our drilling activity, if any, on locations which present the best commodity mix coupled with the most operational efficiency from a development program standpoint. In addition, we expect that continuing to operate the substantial majority of our drilling locations will allow us to reallocate our capital and resources opportunistically in response to

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market conditions. Our disciplined focus on well-level returns in allocating our capital and resources has been a key component of our ability to deliver successful results through various commodity price cycles.

Competitive Strengths

        We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategy:

Geographic Focus in the Prolific U.S. Midcontinent.

        Our operations are focused in the Midcontinent region, targeting liquids-rich opportunities in the Anadarko and Arkoma basins of Texas and Oklahoma. We generally focus on formations characterized by oil and liquids-rich natural gas content, extensive production histories, long-lived reserves, high drilling success rates, and attractive initial production rates. Furthermore, our areas of operation are proximate to well-developed natural gas and liquids midstream infrastructure and oilfield services providers, which we believe reduces the risk of production delays and facilitates adequate takeaway capacity.

Multi-Year Drilling Inventory in Existing and Emerging Resource Plays.

        Our drilling inventory consists of approximately 2,103 gross identified drilling locations in the Anadarko and Arkoma basins, and our development plans target locations that we believe are low-cost, provide attractive economics, present low risk, and support a relatively predictable production profile. As of December 31, 2015, we had identified 711 gross drilling locations in the Cleveland play and 277 gross drilling locations in the Arkoma Woodford shale formation. Our concentrated leasehold position has been delineated largely through drilling on our Cleveland leasehold, which we expanded substantially through our Chalker and Sabine acquisitions and more recently through our leasing efforts. We have also expanded, in prior years, through joint development agreements with large independent producers and major oil and gas companies in the Cleveland and Woodford formations. Furthermore, we have identified additional locations in several emerging resource plays that we intend to explore and develop in the coming years, including 279 gross locations in the Tonkawa formation and 473 gross locations in the Marmaton formation.

Extensive Operational Expertise and Low-Cost Operating Structure.

        Drilling horizontal wells has been our primary approach to field development since 1998. Having drilled over 650 horizontal wells in nine formations in our areas of operation since 1996, we have established systematic protocols that we believe provide repeatable results. We also have established relationships with oilfield services providers, allowing for continued cost efficiencies. As an example, we have consistently drilled horizontal Cleveland wells at a meaningfully lower cost than most of our competition in the same area. Through our focus on drilling, completion and operational efficiencies, we are able to effectively control costs and deliver attractive rates of return and profitability.

Strong Financial Position and Conservative Policies.

        We are committed to maintaining a conservative financial profile in order to preserve operational flexibility and financial stability. We believe that our operating cash flow, together with projected availability under our senior secured revolving credit facility, provide us with the financial flexibility to pursue acquisitions, joint development agreements and organic leasing opportunities. In addition, we have historically hedged a significant amount of our production from oil, gas and NGLs. For the three years ended December 31, 2015, approximately 79% of our total production was protected by commodity hedges. Our hedge position is reviewed monthly to evaluate the impact of new wells coming online and changes to our development program. We intend to continue to actively hedge our future production in order to reduce the impact of commodity price volatility on our cash flows and secure our rates of return for up to five years. As of December 31, 2015, the market value of our existing hedges was approximately $217.5 million.

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High Caliber Management Team with Deep Operating Experience and a Proven Track Record.

        Our top five executives average more than 28 years of industry experience and have worked together developing assets for many years, resulting in a high degree of continuity. We have assembled a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells and with fracture stimulation of unconventional formations, which has resulted in a successful track record of reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team have previously held positions with both major and large independent oil and natural gas companies, including ExxonMobil, BP, Shell, Southwestern Energy, Marathon and Standard Oil.

Alignment of Management Team.

        Our predecessor company was founded in 1988 by our CEO, Jonny Jones, in continuation of his family's history in the oil and gas business, which dates back to the 1920's. Jones family members and our management team controlled approximately 21.8% of our combined voting power and economic interest as of December 31, 2015. We believe the equity interests of our officers and directors align their interests and provide substantial incentive to grow the value of our business.

Recent Developments

        See Note 15, "Subsequent Events," in the Notes to Consolidated Financial Statements for discussion of recent developments.

Our Operations

Our Areas of Operations

        We own leasehold interests in oil and natural gas producing properties, as well as in undeveloped acreage, substantially all of which are located in the Anadarko and Arkoma basins in Texas and Oklahoma. The majority of our interests are in producing properties located in fields characterized by what we believe to be long-lived, predictable production profiles and repeatable development opportunities. Specifically, our properties and wells are located in fields that generally have been developed over a long period of time, typically decades. Given the long productive history of these fields, there is substantial midstream and service infrastructure in place, including natural gas and NGL pipelines and natural gas processing plants. Observing the performance of these fields over many years allows for greater understanding of production and reservoir characteristics, making future performance more predictable. For a discussion of the risks inherent in oil and natural gas production, please read "Risk Factors—Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations."

Anadarko Basin

        Approximately 84% of our estimated proved reserves as of December 31, 2015 and approximately 82% of our average daily net production for the year ended December 31, 2015 were located in the Anadarko basin. The Anadarko basin is one of the most prolific oil and natural gas producing basins in the United States, covering approximately 50,000 square miles primarily in Oklahoma, but also including the upper Texas Panhandle, southwestern Kansas, and southeastern Colorado.

        The basin has an especially well developed interval of productive Pennsylvanian age sedimentary rocks, up to 15,000 feet thick. Our wells in this area produce oil, natural gas and NGLs from various formations at depths from approximately 7,000 feet to 12,000 feet. We drilled 51 gross (47 net) wells as

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operator in the Anadarko basin in 2015. Our operations in the Anadarko basin are primarily focused on the Cleveland formation where we have 573 producing wells. We also have acreage in the Tonkawa, Marmaton, Granite Wash, and various Pennsylvanian-age shale formations located in the eastern portion of the Texas Panhandle and western Oklahoma.

        Producing Formations.    Our production in the Anadarko basin is currently derived primarily from the following formations, where we have 823 gross (483 net) producing wells and where we have identified 1,826 gross (928 net) drilling locations as of December 31, 2015, of which 357 have proved undeveloped reserves attributed to them as of December 31, 2015. See "Drilling Locations" for more information regarding the processes and criteria through which these drilling locations were identified.

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Cleveland Formation.  Our Cleveland acreage is primarily located in Ochiltree, Lipscomb, Hutchinson, and Hemphill Counties in Texas and Ellis County in Oklahoma. The Cleveland formation ranges from depths of approximately 7,000 feet to 8,800 feet and is characterized by a tight, shaly sand with low permeability that lends itself to improved recovery through enhanced drilling and completion techniques.

As of December 31, 2015, we operated 573 gross (410 net) wells producing from the Cleveland formation with an average working interest of 72%. Our Cleveland properties contained 80.6 MMBoe of estimated net proved reserves as of December 31, 2015, 63% of which are oil and NGLs, and generated an average daily net production of 18.4 MBoe/d for the year ended December 31, 2015. We have identified 711 gross (455 net) drilling locations in the Cleveland formation as of December 31, 2015. Of these 711 locations, 307 locations (43%) have proved undeveloped reserves attributed to them as of December 31, 2015.

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Tonkawa Formation.  As of December 31, 2015, we identified 279 gross (168 net) drilling locations in the Tonkawa formation primarily in Lipscomb and Hemphill Counties in Texas. In addition, the Tonkawa formation is present in the area of other properties we own located primarily in Ellis and Roger Mills Counties in Oklahoma. The Tonkawa is a newly-targeted horizontal oil formation at depths of approximately 6,000 feet to 8,000 feet and is characterized by fine to very fine-grained shallow marine sandstone, ranging in thickness from 20 feet to 40 feet.

We drilled our first horizontal Tonkawa well in May 2010 and drilled two additional horizontal wells in the formation under a farm-out with Samson Resources that is not part of our current leasehold. During 2014, we drilled six additional test wells in different areas of the Company's leasehold acreage in the Tonkawa formation. As of December 31, 2015, our Tonkawa properties contained 0.2 MMBoe of estimated net proved reserves.

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Marmaton Formation.  As of December 31, 2015, we identified 473 gross (283 net) drilling locations in the Marmaton formation. Our properties in the Marmaton formation are all undeveloped and span three sub- formations: properties located primarily in Ellis County, Oklahoma characterized by fluvio-deltaic sands, properties located primarily in Northeast Ochiltree and Northwest Lipscomb Counties, Texas, characterized by shallow marine sands, and properties located primarily in Ochiltree County, Texas characterized by algal reef complex. The Marmaton sand is a tight, shaly sand with similar reservoir characteristics to the Cleveland. The Marmaton sand ranges in thickness from 40 feet to 80 feet while the reef ranges from 80 feet to 150 feet.

•

Granite Wash Formation.  Our Granite Wash acreage is primarily located in Roberts, Hemphill and Wheeler Counties in Texas and Roger Mills, Beckham, Custer and Washita Counties in Oklahoma. The Granite Wash spans multiple zones from depths of approximately 9,000 feet to 12,000 feet and is composed of stacked, low permeability, variable lithology alluvial fan deltaic deposits.

9

As of December 31, 2015, we operated 30 gross (19 net) producing wells in this formation with an average working interest of 63%. Our Granite Wash properties contained 2.2 MMBoe of estimated net proved reserves as of December 31, 2015, approximately 45% of which are oil and NGLs. We have 363 gross (22 net) remaining drilling locations in the Granite Wash formation as of December 31, 2015.

        Future Potential Opportunities.    Our current leasehold position provides longer term potential exposure to other prospective formations in the Anadarko basin, including the Atoka, Cherokee, Douglas, Cottage Grove, and Upper and Lower Morrow formations. The Atoka and Cherokee formations, in particular, have attractive geologic properties, and we may elect to pursue their development in the future.

Arkoma Basin

        Approximately 16% of our estimated proved reserves as of December 31, 2015, and approximately 18% of our average daily net production for the year ended December 2015, were located in the Arkoma basin. The Arkoma basin is a historically prolific, largely gas-prone basin extending from eastern Oklahoma into western Arkansas. The basin produces natural gas, oil and NGLs from multiple horizons, which range in depth from 500 to 21,000 feet.

        As of December 31, 2015, we operated approximately 43% of our properties in the Arkoma basin and produce primarily from the Woodford formation.

•

Woodford Shale Formation.  Our properties in the Woodford shale formation are located primarily in Atoka, Coal, Pittsburg and Hughes Counties in eastern Oklahoma. The Woodford shale formation ranges from depths of approximately 5,000 feet to 12,700 feet and is composed of 75 to 220-foot thick black siliceous shale in our operating area. The Woodford shale in this area is prospective for natural gas with a high concentration of associated NGLs.

As of December 31, 2015, we operated 152 gross (59 net) producing wells in the formation with an average working interest of 39%. Our Woodford shale formation properties contained 16.3 MMBoe of estimated net proved reserves as of December 31, 2015, 32% of which are oil and NGLs, and generated an average daily net production of 3.6 MBoe/d for the year ended December 31, 2015. We identified 277 gross (45 net) drilling locations in the Woodford shale formation as of December 31, 2015, of which 20% had proved undeveloped reserves attributed to them.

Drilling Locations

        We have identified a total of 2,103 gross (973 net) drilling locations, all of which are horizontal drilling locations. Of these 2,103 locations, 1,536 locations are attributable to acreage that is currently held by production and approximately 412 (20%) are attributable to proved undeveloped reserves as of December 31, 2015. In order to identify drilling locations, we apply geologic screening criteria based on the presence of a minimum threshold of reservoir thickness in a section and then consider the number of sections and the appropriate well density to develop the applicable field. In making these assessments, we include properties in which we hold operated and non-operated interests, as well as redevelopment opportunities. Once we have identified acreage that is prospective for the targeted formations, well placement is determined primarily by the regulatory spacing rules prescribed by the governing body in each of our operating areas. Wells drilled in the Cleveland formation adhere to 128-acre spacing (5 wells per section) while wells in the Woodford shale formation are developed on 80-acre and 120-acre spacing, depending on the area. Wells drilled in the Granite Wash formation were developed on 128-acre or 213-acre spacing. Wells drilled in the Tonkawa and Marmaton formations adhere to 160-acre spacing. We view the risk profiles for the Tonkawa and Marmaton formations as

10

being higher than for our other drilling locations due to relatively less available production data and drilling history.

        Our identified drilling locations are scheduled to be drilled over many years. The ultimate timing of the drilling of these locations will be influenced by multiple factors, including oil, natural gas and NGL prices, the availability and cost of capital, drilling, completion and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, processing, marketing and pipeline transportation constraints, regulatory approvals and other factors. In addition, a number of our identified drilling locations are associated with joint development agreements, and if we do not meet our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to continue to develop certain acreage covered by that agreement. For a discussion of the risks associated with our drilling program, see "Risk Factors—Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent or delay associated expected production. In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drilling locations."

        The Company currently does not anticipate drilling new wells in the near term. When we resume drilling, our expectation is that we will primarily focus on the Anadarko basin. As a result, the Company will not spud the required number of additional wells per the joint development agreement between Jones Energy and Vanguard Natural Resources within the prescribed time period to maintain rights to the additional future drilling locations. The loss of these drilling locations, along with other near term lease expirations in the Arkoma, have contributed to a reduction in the Company's Woodford proved undeveloped reserve figures and total drilling location count. As of December 31, 2014, the Company had 777 gross (85 net) drilling locations in the Woodford shale formation. The total number of Arkoma drilling locations removed from the Company's 2014 year-end inventory during 2015 totaled 496 gross locations and 40 net locations, including 42 gross (eight net) locations associated with proved undeveloped reserves. These Arkoma drilling locations had no associated PV-10 value in the Company's year-end 2015 proved reserves based on SEC pricing and definitions.

Estimated Proved Reserves

        The following table sets forth summary data with respect to our estimated net proved oil, natural gas and NGLs reserves as of December 31, 2015, 2014 and 2013, which are based upon reserve reports of Cawley, Gillespie & Associates, Inc., ("Cawley Gillespie"), our independent reserve engineers.

11

Cawley Gillespie's reports were prepared consistent with the rules and regulations of the SEC regarding oil and natural gas reserve reporting in effect during such periods.

	As of December 31,
	2015		2014		2013
Reserve Data:
Estimated proved reserves:
Oil (MBbls)		25,408		27,683		16,688
Natural gas (MMcf)		261,596		292,277		236,648
NGLs (MBbls)		32,649		38,870		32,915
Total estimated proved reserves (MBoe)(1)		101,657		115,266		89,045
Estimated proved developed reserves:
Oil (MBbls)		11,032		10,773		7,129
Natural gas (MMcf)		169,651		160,877		139,623
NGLs (MBbls)		19,670		22,555		19,101
Total estimated proved developed reserves (MBoe)(1)		58,977		60,141		49,501
Estimated proved undeveloped reserves:
Oil (MBbls)		14,376		16,910		9,559
Natural gas (MMcf)		91,945		131,400		97,025
NGLs (MBbls)		12,980		16,315		13,814
Total estimated proved undeveloped reserves (MBoe)(1)		42,680		55,125		39,544
PV-10 (in millions)(2)	$	470	$	1,502	$	1,017
Standardized measure (in millions)(3)		465		1,388		941

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(2)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See "Reconciliation of PV-10 to Standardized Measure" below.

(3)

Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas.

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        The following table sets forth the benchmark prices used to determine our estimated proved reserves for the periods indicated.

	As of December 31,
	2015		2014		2013
Oil, Natural Gas and NGLs Benchmark Prices:
Oil (per Bbl)(1)	$	50.25	$	94.99	$	96.78
Natural gas (per MMBtu)(2)		2.59		4.35		3.67
NGLs (per Bbl)(3)		17.63		33.17		28.33

(1)

Benchmark prices for oil reflect the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months using WTI Cushing posted prices. These prices were utilized in the reserve reports prepared by Cawley Gillespie and in management's internal estimates and are adjusted by well for content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2015, 2014 and 2013, the average realized prices for oil were $45.97, $91.06 and $91.74 per Bbl, respectively.

(2)

Benchmark prices for natural gas in the table above reflect the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, respectively, using Henry Hub prices. These prices were utilized in the reserve reports prepared by Cawley Gillespie and in management's internal estimates and are adjusted by well for content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2015, 2014 and 2013, the average realized prices for natural gas were $2.37, $4.16 and $3.13 per MMBtu, respectively.

(3)

Prices for NGLs in the table above reflect the average realized prices for the prior 12 months assuming ethane is recovered from the natural gas stream. Benchmark prices for NGLs vary depending on the composition of the NGL basket and current prices for the various components thereof, such as butane, ethane, and propane, among others. Due to declines in ethane prices relative to natural gas prices, beginning in 2012, purchasers of our Woodford production have been electing not to recover ethane from the natural gas stream and instead are paying us based on the natural gas price for the ethane left in the gas stream. As a result of the increased energy content associated with the returned ethane and the absence of plant shrinkage, this ethane rejection has increased the incremental revenue and volumes that we receive for our natural gas product relative to what we would have received if the ethane was separately recovered, but has reduced physical barrels of liquid ethane that we are selling.

Reserves Sensitivities

        Assuming NYMEX strip pricing as of February 29, 2016 through 2022 and keeping pricing flat thereafter, instead of 2015 SEC pricing, and leaving all other parameters unchanged, the Company's proved reserves would have been 101.3 MMBoe and the PV-10 value of proved reserves would have been $376 million. This alternative pricing scenario is provided only to demonstrate the impact that the current pricing environment may have on reserves volumes and PV-10. There is no assurance that these prices will actually be realized. The value of our proved reserves as of December 31, 2015 calculated using SEC pricing is higher than the value of our proved reserves calculated using current market prices. Using SEC pricing of December 31, 2015, our total estimated proved reserves were 101.7 MMBoe and the PV-10 value of proved reserves was $470 million.

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Reconciliation of PV-10 to Standardized Measure

        PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

        The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at December 31, 2015, 2014 and 2013.

	As of December 31,
(in millions)	2015		2014		2013
PV-10	$	470	$	1,502	$	1,017
Present value of future income taxes discounted at 10%		5		114		76
Standardized measure	$	465	$	1,388	$	941

Internal Controls

        Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by our corporate reservoir engineering staff. We maintain internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management team on a semi-annual basis. We expect to have our reserve estimates evaluated by Cawley Gillespie, our independent third-party reserve engineers, or another independent reserve engineering firm, at least annually.

        Our internal professional staff works closely with Cawley Gillespie to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. We provide all of the reserve information maintained in our secure reserve engineering database to the external engineers, as well as other pertinent data, such as geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves. Various procedures are used to ensure the accuracy of the data provided to our independent petroleum engineers, including review processes. Changes in reserves from the previous report are closely monitored. Reconciliation of reserves from the previous report, which includes an explanation of all significant changes, is reviewed by both the engineering department and upper management, including our chief operating officer. Our independent petroleum engineers prepare our annual reserves estimates, whereas interim estimates are internally prepared.

Technology Used to Establish Proved Reserves

        Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically

14

producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Cawley Gillespie employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and well completion using similar techniques.

Qualifications of Responsible Technical Persons

        Internal engineer.    Eric Niccum, our Executive Vice President and Chief Operating Officer, is the technical specialist primarily responsible for overseeing the preparation of our reserves estimates. Mr. Niccum is also responsible for liaising with and oversight of our third-party reserve engineer. Mr. Niccum is a graduate of Purdue University with a Bachelor of Science degree in Mechanical Engineering. He has 22 years of energy experience.

        Cawley Gillespie.    Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists. The firm has provided petroleum consulting services to the oil and gas industry for over 50 years. No director, officer, or key employee of Cawley Gillespie has any financial ownership in us or any of our affiliates. Cawley Gillespie's compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Cawley Gillespie has not performed other work for us that would affect its objectivity. The engineering audit presented in the Cawley Gillespie report was supervised by W. Todd Brooker, Senior Vice President at Cawley Gillespie. Mr. Brooker is an experienced reservoir engineer having been a practicing petroleum engineer since 1989. He has more than 25 years of experience in reserves evaluation and joined Cawley Gillespie as a reserve engineer in 1992. He has a Bachelor's of Science Degree in Petroleum Engineering from the University of Texas at Austin and is a Registered Professional Engineer in the State of Texas (License No. 83462).

Development of Proved Undeveloped Reserves

        As of December 31, 2015, none of our proved undeveloped reserves at December 31, 2015 were scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. However, certain of our proved undeveloped reserves are associated with joint development agreements with third parties that include obligations to drill a specified minimum number of wells in a time frame that is shorter than five years. If we do not meet our obligation to drill the minimum number of wells specified in a joint development agreement, we will lose the right to continue to develop the undeveloped acreage covered by the agreement, which in some cases would result in a reduction in our proved undeveloped reserves. Historically, our drilling

15

and development programs were substantially funded from our cash flow from operations. Our expectation is to continue to fund our drilling and development programs primarily from our cash flow from operations and projected availability under our senior secured revolving credit facility. Based on our current expectations of our cash flows and drilling and development programs, which include drilling of proved undeveloped locations, we believe that we will be able to fund the drilling of our current inventory of proved undeveloped locations and our expansion activities in the next five years from our cash flow from operations and borrowings under our credit facilities. For a more detailed discussion of our liquidity position, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

	Total (MMBoe)
Estimated Proved Undeveloped Reserves
December 31, 2013		39.5
Extensions and discoveries		15.7
Conversion to proved		(10.1	)
Purchases of minerals in place		9.8
Sales of minerals in place		—
Revisions of previous estimates		0.2
December 31, 2014		55.1
Extensions and discoveries		3.7
Conversion to proved		(8.2	)
Purchases of minerals in place		—
Sales of minerals in place		—
Revisions of previous estimates		(7.9	)
December 31, 2015		42.7

        Our proved undeveloped reserves have decreased from 55.1 MMBoe at December 31, 2014 to 42.7 MMBoe at December 31, 2015 due to (i) the conversion of 8.2 MMBoe of proved undeveloped reserves to proved developed reserves; (ii) net negative revisions of 7.9 MMBoe, primarily due to reduced commodity pricing partially offset by reduced future development costs; and (iii) additions of 3.7 MMBoe from extensions and discoveries. Proved undeveloped reserves decreased as a percentage of total reserves from 48% for the year ended December 31, 2014 to 42% for the year ended December 31, 2015. Proved undeveloped reserves increased as a percentage of total reserves from 44% for the year ended December 31, 2013 to 48% for the year ended December 31, 2014.

        For the year ended December 31, 2015, we converted 8.2 MMBoe of proved undeveloped reserves to proved developed reserves or 15% of total proved undeveloped reserves booked at December 31, 2014. We incurred approximately $105.6 million in capital to convert proved undeveloped reserves to proved developed reserves during the year ended December 31, 2015. Our 2015 capital expenditures totaled $200.1 million excluding the impact of asset retirement costs, of which $173.2 million was utilized to drill and complete operated wells including wells that had no proved undeveloped reserves associated with them prior to drilling. The Company has established an initial capital budget of $25 million for 2016, with the majority dedicated to capital workovers and field optimization activities. Costs of proved undeveloped reserve development in 2015 do not represent the total costs of these conversions, as additional costs may have been incurred in previous years. Estimated future development costs relating to the development of 2015 year-end proved undeveloped reserves is $446 million, all of which is scheduled to be incurred within five years. All drilling locations classified as proved undeveloped reserves in the year-end reserve report are scheduled to be drilled within five years of initial proved reserve booking.

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Operating Data

        The following table sets forth summary data regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated.

	Year Ended December 31,
	2015		2014		2013
Production and Operating Data:
Net Production Volumes(1):
Oil (MBbls)		2,583		2,475		1,557
Natural gas (MMcf)		23,839		21,922		17,575
NGLs (MBbls)		2,618		2,345		1,724
Total (MBoe)		9,174		8,474		6,210
Average net production (Boe/d)		25,134		23,216		17,014
Average Sales Price(2):
Oil (per Bbl)	$	44.15	$	88.93	$	93.22
Natural gas (per Mcf)		1.91		3.78		3.16
NGLs (per Bbl)		13.36		32.14		33.30
Combined (per Boe) realized		21.21		44.65		41.56
Average Costs per Boe:
Lease operating	$	4.47	$	4.46	$	4.05
Production and ad valorem taxes		1.32		2.66		2.50
Depreciation, depletion and amortization		22.40		21.44		18.38
General and administrative(3)		3.64		3.04		5.14

(1)

The Lipscomb SE field constituted approximately 27% of our estimated proved reserves as of December 31, 2015. Our production from the Lipscomb SE field was 2,465 MBoe, 2,862 MBoe and 1,751 MBoe for the years ended December 31, 2015, 2014 and 2013, respectively. The 2015 production was comprised of 889 MBbls of oil, 5,239 MMcf of natural gas and 702 MBbls of NGLs. The 2014 production was comprised of 1,274 MBbls of oil, 5,337 MMcf of natural gas and 699 MBbls of NGLs. The 2013 production was comprised of 858 MBbls of oil, 2,786 MMcf of natural gas and 430 MBbls of NGLs.

The Lipscomb field constituted approximately 24% of our estimated proved reserves as of December 31, 2015. Our production from the Lipscomb field was 2,237 MBoe, 1,467 MBoe and 1,105 MBoe for the years ended December 31, 2015, 2014 and 2013, respectively. The 2015 production was comprised of 637 MBbls of oil, 5,271 MMcf of natural gas and 721 MBbls of NGLs. The 2014 production was comprised of 408 MBbls of oil, 3,394 MMcf of natural gas and 494 MBbls of NGLs. The 2013 production was comprised of 215 MBbls of oil, 2,963 MMcf of natural gas and 395 MBbls of NGLs.

(2)

Prices do not include the effects of derivative cash settlements.

(3)

General and administrative includes non-cash stock-based compensation of $8.0 million, $4.8 million and $13.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Excluding stock-based compensation from the above metric results in average general and administrative cost per Boe of $2.77, $2.47 and $2.95 for the years ended December 31, 2015, 2014 and 2013, respectively.

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Drilling Activity

        The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

	Year Ended December 31,
	2015				2014				2013
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		53		47		144		119		97		61
Mechanical failure		1		1		1		1		—		—
Dry		—		—		—		—		—		—
Exploratory Wells:
Productive		—		—		—		—		—		—
Dry		—		—		1		1		—		—
Total Wells:
Productive		53		47		144		119		97		61
Mechanical failure		1		1		1		1		—		—
Dry		—		—		1		1		—		—
Total(1)		54		48		146		121		97		61

(1)

In 2015, the total presented includes one mechanical failure that was not deemed to be a completed well by the Company because it was only drilled to 1,000 feet and abandoned. Therefore, outside of the table above, this mechanical failure has been excluded from our well count.

        For the three years ended December 31, 2015, we had one gross (one net) developmental or exploratory well that was deemed to be a dry well. In this same period, we experienced a total of one gross (one net) mechanical failure that was not reservoir related. As of December 31, 2015, there were no development wells in the process of drilling or completion. For the three years ended December 31, 2015, we drilled 294 gross (227 net) wells as operator with over a 99% success rate.

        From January 1, 2015 through December 31, 2015, we successfully drilled 53 gross proved undeveloped wells and completed 70 gross proved undeveloped wells.

Productive Wells

        The following table sets forth our total gross and net productive wells by oil or natural gas classification as of December 31, 2015.

	Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Operated(1)		290		236		308		232		598		468
Non-operated		70		11		348		71		418		82
Total		360		247		656		303		1,016		550

(1)

Includes wells on which we act as contract operator.

        Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

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Acreage Data

        The following table sets forth certain information regarding the developed and undeveloped acreage in which we have an interest as of December 31, 2015 for each of our producing areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. Acreage that is prospective for the Tonkawa, Marmaton and other formations is included in these totals as these formations overlie one another throughout much of our acreage. As of December 31, 2015, over 80% of our leasehold acreage was held by existing production.

	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
Cleveland		143,607		91,651		37,746		26,049		181,353		117,700
Granite Wash		10,553		6,617		—		—		10,553		6,617
Woodford		12,363		4,417		20		1		12,383		4,418
Other		19,594		7,444		4,341		1,198		23,935		8,642
All properties		186,117		110,129		42,107		27,248		228,224		137,377

Undeveloped Acreage Expirations

        The following table sets forth the number of gross and net undeveloped acres as of December 31, 2015 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration.

	Expiring 2016				Expiring 2017				Expiring 2018				Thereafter
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Cleveland		4,185		2,715		12,641		10,657		19,941		12,071		979		606
Woodford		20		1		—		—		—		—		—		—
Granite Wash		—		—		—		—		—		—		—		—
Other		2,449		1,148		1,575		43		—		—		317		7
All properties		6,654		3,864		14,216		10,700		19,941		12,071		1,296		613

        A majority of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations have commenced or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of operations or production in commercial quantities. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We do not have any of our proved undeveloped reserves as of December 31, 2015 attributed to acreage whose lease expiration date precedes the scheduled initial drilling date. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors' fee lease terms as they relate to both primary term and royalty interests.

Competition

        The oil and natural gas industry is highly competitive. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory

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prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Please read "Risk Factors—We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues."

        We are also affected by competition for drilling rigs, equipment, services, supplies and qualified personnel. Recently, the United States onshore oil and natural gas industry has begun to experience a surplus of drilling and completion rigs, equipment, pipe and personnel, due to significantly lower commodity prices. Although this has provided a temporary respite from the previous high demand environment, there is no assurance that market forces will not revert to the previous situation which resulted in delayed development drilling and other exploration activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such changes may occur or how they would affect our development and exploitation programs.

Segment Information and Geographic Areas

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States, as described under "—Our Operations—Our Areas of Operations."

Oil and Natural Gas Leases

        The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 17% to 25%. Our net revenue interests average 55% for our operated leases and 38% including all operated and non-operated leases.

        Over 80% of our leases (based on net acreage) are held by production and do not require lease rental payments.

Marketing and Major Customers

        Our oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for oil and liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. We do not own any oil or liquids pipelines or other assets for the transportation of those commodities, and transportation costs related to moving oil are deducted from the price received for oil. In September of 2014, we signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to our dedicated leases in Texas. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. We have reserved capacity of up to 12,000 barrels per day on the system with the potential to increase throughput at a future date.

        Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to natural gas gathering and marketing companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. On virtually all of our natural gas production, we are paid for the extracted NGLs based on a negotiated percentage of the proceeds that are generated from the customer's sale of the liquids, or based on other negotiated pricing arrangements. We do not own any natural gas pipelines or other assets for the transportation of natural gas.

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        In 2015, changes in NGL prices again altered market conditions. Due primarily to the large supply of the major NGL component products on the market, the composite price of NGL components dropped significantly over the last year. For a discussion of the effect of recent changes in NGL prices, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook."

        During the year ended December 31, 2015, the largest purchasers were Valero Energy Corp. ("Valero"), ETC Field Services LLC, Plains Marketing LP ("Plains Marketing"), NGL Energy Partners LP, and Unimark LLC, which accounted for approximately 18%, 17%, 16%, 15% and 7% of consolidated oil and gas sales, respectively. If we were to lose any one of our customers, the loss could temporarily delay production and sale of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes. For a discussion of the risks associated with the loss of key customers, please read "Risk factors—Our customer base is concentrated, and the loss of any one of our key customers could, therefore, adversely affect our financial condition and results of operations."

Seasonality

        Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters sometimes lessen this fluctuation.

Title to Properties

        Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties.

        As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to material defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

        We conduct a portion of our operations through joint development agreements with third parties. Certain of our joint development agreements include complete-to-earn arrangements, whereby we are assigned title to properties from the third-party after we complete wells. Occasionally, delivery of such assignments may be delayed. Furthermore, certain of our joint development agreements specify that assignments are only to occur when the wells are capable of producing hydrocarbons in paying quantities. These additional conditions to assignment of title may from time to time apply to wells of substantial value.

        We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens,

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restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report on Form 10-K.

Regulations

        Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and limit the number of wells or locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

        Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress and federal agencies, the states, and the courts. We cannot predict when or whether any such proposals may become effective. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Matters and Regulation

        Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment, as well as the discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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require the installation of pollution control equipment in connection with operations;

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restrict or prohibit our drilling and production activities during periods when such activities might affect wildlife;

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place restrictions or regulations upon the types, quantities or concentrations of materials or substances used in our operations;

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restrict the types, quantities or concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

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limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells.

        These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, federal, state and local lawmakers and agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs.

        The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Solid and Hazardous Waste Handling and Releases

        The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous waste. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. In the course of our operations, however, we generate some industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. Although a substantial amount of the waste generated in our operations are regulated as non-hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous waste. Moreover, it is possible that certain oil and gas exploration and production wastes now classified as non- hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

        The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as "Superfund," and comparable state laws and regulations impose liability without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency, or the EPA, and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

        Although CERCLA generally exempts "petroleum" from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA's definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been

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designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

        We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to the RCRA, CERCLA, and analogous state laws. Spills or other contamination required to be remediated have not required material capital expenditures to date. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

        The federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States or waters of the state, both broadly defined terms. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs. The EPA and the U.S. Army Corps of Engineers adopted in June 2015 a rule redefining the term "waters of the United States," which establishes the scope of regulated waters under the Clean Water Act. The final rule is expected to expand federal jurisdiction under the Clean Water Act. The rule has been challenged and was stayed by federal courts and will become applicable if the courts do not continue the stay of the rule during the litigation. The EPA also proposed regulations in 2015 under the Clean Water Act to set a zero discharge standard for wastewater discharges from hydraulic fracturing and other natural gas production activities to publicly-owned treatment works. A final rule is expected in 2016.

Safe Drinking Water Act

        The SDWA regulates, among other things, underground injection operations. Congress has considered legislation which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. If enacted, such legislation could impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals

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used in the process could adversely affect ground water. In addition, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to the Underground Injection Control program in states in which the EPA is the permitting authority and released permitting guidance on the use of diesel fuel as an additive in hydraulic fracturing fluids. The EPA has also commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. The Department of Energy also studied hydraulic fracturing and provided broad recommendations regarding best practices and other steps to enhance companies' safety and environmental performance of hydraulic fracturing. If the pending or similar legislation is enacted or other new requirements or restrictions regarding hydraulic fracturing are adopted as a result of these studies, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

Other Regulation of Hydraulic Fracturing

        On May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, the Bureau of Land Management, or BLM, adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands; however, a federal district court has stayed the effectiveness of these BLM rules as challenges to the rules are proceeding. BLM also proposed new rules in January 2016 to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On October 26, 2015, the U.S. National Park Service, or NPS, proposed to update its regulations governing non-federal oil and gas rights. Most notably, the NPS rulemaking would eliminate two provisions that exempt approximately 60% of the oil and gas operations located within the national park system from the requirement to obtain NPS approval of a proposed plan of operations before commencing non-federal oil and gas operations in an NPS unit and would clarify well stimulation (including hydraulic fracturing) information requirements and operating standards. The Interagency Working Group on Unconventional Natural Gas and Oil was created by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.

        Hydraulic fracturing is also subject to regulation at the state and local levels. Several states have proposed or adopted legislative or administrative rules regulating hydraulic fracturing operations. For example, the Railroad Commission of Texas, implementing a state law passed in June 2011, adopted the Hydraulic Fracturing Chemical Disclosure Rule on December 13, 2011. The rule requires public disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after February 1, 2012. Additionally, Texas has authorized the Texas Commission on Environmental Quality to suspend water use rights for oil and gas users in the event of serious drought conditions and has imposed more stringent emissions, monitoring, inspection, maintenance, and repair requirements on Barnett Shale operators to minimize Volatile Organic Compound, or VOC, releases. Other states that we operate in, including Oklahoma, have adopted similar chemical disclosure measures. Some states, including Texas and Oklahoma, also assert the authority to shut down injection wells that are deemed to contribute to induced seismicity, or seismic activity that is caused by human activity. For example, on August 3, 2015, the Oklahoma Corporation Commission adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in Oklahoma. Please see "Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing and other oil and gas production activities as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production" for a further discussion of state hydraulic fracturing regulation. In

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addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Oil Pollution Act

        The primary federal law related to oil spill liability is the Oil Pollution Act, or the OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. A liable "responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns strict joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Air Emissions

        Our operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or injunctions or require us to forego construction, modification or operation of certain air emission sources.

        We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, on April 17, 2012, the EPA released final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. The rules became effective on October 15, 2012. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants. In October 2012, several challenges to the EPA's rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since made several changes to the rules and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA may issue new rules. These rules that took effect on October 15, 2012, as well as any modifications to these rules or additional rules, could require a number of modifications to our operations including the installation of new equipment. We have already reported some of our facilities as being subject to these rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy reporting and other administrative requirements associated with these rules. Additionally, on September 18, 2015 the EPA proposed to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector as a measure to implement the Climate Action Plan and

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proposed a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Final rules are expected in 2016. Further, in 2015, the EPA adopted a lower national ambient air quality standard for ozone. This lower standard may cause additional areas to be designated as ozone nonattainment areas, causing states to revise their implementation plans to require additional emissions control equipment and to impose more stringent permit requirements on facilities in those areas.

Endangered Species and Migratory Birds

        The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered, activities adversely affecting that species or its habitat may be considered "take" and may incur liability. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Criminal liability can attach for even an incidental taking of migratory birds, and the federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities.

        We conduct operations in areas where certain species that are listed as threatened or endangered under the ESA may be present. For example, our operations in the Arkoma basin of Oklahoma overlap with the range of the American Burying Beetle, which is listed as endangered. The presence of endangered or threatened species may force us to modify or terminate our operations in certain areas. Additionally, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or limit future development activity in the affected areas. On March 27, 2014, the U.S. Fish and Wildlife Service listed the Lesser Prairie Chicken as a threatened species under the Endangered Species Act. The designated habitat for the Lesser Prairie Chicken encompasses significant portions of our properties in the Anadarko basin. In a special rule under ESA Section 4(d) released simultaneously with the decision to list the Lesser Prairie Chicken as threatened, the Fish and Wildlife Service will exempt from "take" certain oil and gas and other activities conducted by a participant that result in an "incidental take" of the Lesser Prairie Chicken as long as the participant is enrolled in, and operating in compliance with, a range-wide conservation plan endorsed by the Fish and Wildlife Service. The range-wide conservation plan also includes a Candidate Conservation Agreement with Assurances (CCAA) component that provides "take" coverage for properties enrolled into the CCAA before the listing is effective. To mitigate the risk of liability from "incidental takes" of the Lesser Prairie Chicken, we enrolled affected leasehold interests in the CCAA. However, environmental groups challenged the listing decision and special 4(d) rule in a suit filed in federal district court in the District of Columbia on June 17, 2014. These groups are attempting to compel a more restrictive listing of the Lesser Prairie Chicken as endangered, rather than threatened, and are seeking to invalidate the special 4(d) rule. While these same environmental groups also filed a notice of intent to sue concerning the CCAA on April 10, 2014, the suit filed in federal court did not include a challenge to the CCAA. Other suits challenging the scientific basis for the listing were filed by affected states and the oil and gas industry in Texas and Oklahoma. On September 1, 2015 a federal district court in Texas vacated the listing of the Lesser Prairie Chicken as a threatened species, holding the Fish and Wildlife Service did not sufficiently account for voluntary range-wide conservation efforts being implemented to protect the species. The Fish and Wildlife Service moved to keep the rule in effect pending further agency action; the court has ordered the parties to mediate. We continue to evaluate the impact of these rules and the ongoing legal challenges on our operations. As with any other species in areas that we operate, the listing of the Lesser Prairie Chicken under the Endangered Species Act could force us to incur additional costs and delay or otherwise limit or terminate our operations.

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National Environmental Policy Act

        Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current production activities, as well as any exploration and development plans that may be proposed in the future, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Climate Change

        More stringent laws and regulations relating to climate change and greenhouse gases, or GHGs, may be adopted in the future and could cause us to incur material expenses in complying with them. Both houses of Congress have actively considered legislation to reduce emissions of GHGs, but no legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission control, the EPA is regulating GHGs as pollutants under the CAA. The EPA has adopted regulations affecting emissions of GHGs from motor vehicles and is also requiring permit review for GHGs from certain stationary sources that emit GHGs at levels above statutory and regulatory thresholds and are otherwise subject to CAA permitting requirements based on emissions of non-GHG regulated air pollutants. We do not believe our operations are currently subject to these permitting requirements, but if our operations become subject to these or other similar requirements, we could incur significant costs to control our emissions and comply with regulatory requirements.

        In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. On November 9, 2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. The rule requires reporting of GHG emissions by regulated entities to the EPA on an annual basis. Reporting was first required in 2012 for emissions occurring in 2011. In 2015, the EPA added reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines to the GHG reporting rule. We are currently required to monitor and report GHG emissions under this rule, and operational and/or regulatory changes could increase the burden of compliance with GHG emissions monitoring and reporting requirements.

        Because of the lack of any comprehensive legislative program addressing GHGs, there is continuing uncertainty regarding the further development of federal regulation of GHG-emitting sources. Additionally, more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions to acquire and surrender emission allowances. The international, federal, regional and local regulatory initiatives that target GHGs also could adversely affect the marketability of the oil and natural gas we produce. For example, on October 23, 2015, the EPA published the final Clean Power Plan rule. While the rule directly applies to power plants, the Clean Power Plan is targeted at creating a shift from fossil fuels toward renewable power generation; however, the rule has been stayed and is not effective during the judicial review. Also, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and, if it comes into force, would require countries to review and "represent

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a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

        In addition to legislative and regulatory developments, plaintiffs have brought judicial actions under common law theories against greenhouse gas emitting companies in recent years. For example, municipal plaintiffs in Kivalina v. ExxonMobil Corporation, et al, alleged that the defendant corporations' contributions to global warming caused property damage associated with rising sea levels. Although the plaintiffs in Kivalina were ultimately unsuccessful, there is a continuing litigation risk associated with greenhouse gas-emitting activities.

        The federal administration also issued a Climate Action Plan in June 2013. Among other things, the Climate Action Plan directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas industry. As previously mentioned, the EPA proposed a rule in September 2015 to set standards for methane and volatile organic compound emissions from new and modified sources in the oil and gas sector, with a final rule expected in 2016. As a result of this continued regulatory focus and other factors, additional GHG regulation of the oil and gas industry remains a possibility. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

OSHA and Other Laws and Regulation

        We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

        We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation of pollution control activities for the years ended December 31, 2015, 2014 or 2013. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2016 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business activities, financial condition or results of operations.

Offices

        We currently lease approximately 43,000 square feet of office space in Austin, Texas at 807 Las Cimas Parkway, Austin, Texas 78746, where our principal offices are located. The primary lease expires in April 2020. We also lease field offices in Canadian, Texas and McAlester, Oklahoma.

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Employees

        As of December 31, 2015, we had 116 employees, including 46 technical (geosciences, engineering, land), 34 field operations, 31 corporate (finance, accounting, planning, business development, IT, human resources, office management) and 5 management. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services as needed.

Available information

        We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our reports filed with the SEC are made available to read and copy at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

        Our common stock is listed and traded on the New York Stock Exchange under the symbol "JONE." Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

        Through our website, www.jonesenergy.com, you can access, free of charge, electronic copies of all of the documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports.

Item 1A.    Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this Annual Report on Form 10-K, were actually to occur, our business, financial condition or results of operations could be materially adversely affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial may also adversely affect us.

Risks Relating to the Oil and Natural Gas Industry and Our Business:

A substantial or extended decline in oil, natural gas or NGL prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

        The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. The markets for oil, natural gas and NGLs historically have been volatile and were depressed throughout 2015. As an example, during 2015, the NYMEX WTI oil price ranged from more than $61 per Bbl to below $35 per Bbl, the lowest price seen since 2009, and the average daily price for NYMEX Henry Hub natural gas reached a low of $1.63 per MMBtu in December, the lowest price since 1999. These markets will likely continue to be volatile in the future, especially given the current geopolitical conditions. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

•

regional and worldwide economic conditions impacting the supply and demand for oil, natural gas and NGLs;

•

the actions of the Organization of Petroleum Exporting Countries;

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•

the price and quantity of imports of foreign oil, natural gas and NGLs;

•

political conditions regionally, domestically or in other oil and gas-producing regions;

•

the level of domestic and global oil and natural gas exploration and production;

•

the level of domestic and global oil and natural gas inventories;

•

localized supply and demand fundamentals and transportation availability;

•

weather conditions and natural disasters;

•

domestic, local and foreign governmental regulations and taxes;

•

speculation as to the future price of oil, natural gas and NGLs and the speculative trading of oil, natural gas and NGLs;

•

trading prices of futures contracts;

•

price and availability of competitors' supplies of oil, natural gas and NGLs;

•

technological advances affecting energy consumption;

•

the price and availability of alternative fuels; and

•

the impact of energy conservation efforts.

        NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have different uses and different pricing characteristics. NGLs comprised 29% of our 2015 production, and we realized an average price of $13 per barrel, a 58% decrease from the average realized price of our 2014 production. An extended decline in NGL prices could materially and adversely affect our future business, financial condition and results of operations.

        Substantially all of our production is sold to purchasers under contracts with market-based prices. Lower oil, natural gas and NGL prices will reduce our cash flows and the present value of our reserves. If oil, natural gas and NGL prices continue to deteriorate or remain at depressed levels, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, will be reduced at some point, which would negatively impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our capital budget. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. Substantial decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. As an example, total proved reserves decreased by 12%, from 115.3 MMBoe as of December 31, 2014 to 101.7 MMBoe as of December 31, 2015, primarily due to the decline in commodity prices. As a result, a substantial or extended decline in oil, natural gas or NGL prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

        Our future financial condition and results of operations will depend on the success of our exploration, exploitation, development and production activities. Our oil, natural gas and NGLs exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

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In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences, which ultimately results in uncertainty as to when the capital investment required to deploy rigs will create an acceptable return for our shareholders. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•

delays imposed by or resulting from compliance with regulatory and contractual requirements and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;

•

pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

•

equipment failures or accidents;

•

lack of available gathering facilities or delays in construction of gathering facilities;

•

lack of available capacity on interconnecting transmission pipelines;

•

fires and blowouts;

•

adverse weather conditions, such as hurricanes, blizzards and ice storms;

•

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface or subsurface environment;

•

declines in oil, natural gas and NGL prices;

•

limited availability of financing at acceptable rates;

•

title problems; and

•

limitations in the market for oil, natural gas and NGLs.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

        Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, the following:

•

effectively controlling the level of pressure flowing from particular wells;

•

landing our wellbore in the desired drilling zone;

•

staying in the desired drilling zone while drilling horizontally through the formation;

•

running our casing the entire length of the wellbore; and

•

running tools and other equipment consistently through the horizontal wellbore.

        Risks that we face while completing our wells include, but are not limited to, the following:

•

the ability to fracture stimulate the planned number of stages;

•

the ability to run tools the entire length of the wellbore during completion operations; and

•

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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        The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas.

The value of our undeveloped acreage could decline if drilling results are unsuccessful.

        The success of our horizontal drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, declines in oil, natural gas and NGL prices and/or other factors, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Our business requires substantial capital expenditures, and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

        Our exploration, exploitation, development and acquisition activities require substantial capital expenditures. Our total capital expenditures for 2015 were $200.1 million excluding the impact of asset retirement costs. The Company has established an initial capital budget of $25 million for 2016. Historically, we have funded development and operating activities primarily through a combination of equity capital raised from a private equity partner and public equity offerings, through borrowings under our senior secured revolving credit facility, through the issuance of debt securities and through internal operating cash flows. We intend to finance the majority of our capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the issuance of additional debt and equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

•

the estimated quantities of our oil, natural gas and NGL reserves;

•

the amount of oil, natural gas and NGLs we produce from existing wells;

•

the prices at which we sell our production;

•

any gains or losses from our hedging activities;

•

the costs of developing and producing our oil, natural gas and NGL reserves;

•

take-away capacity;

•

our ability to acquire, locate and produce new reserves;

•

the ability and willingness of banks to lend to us; and

•

our ability to access the equity and debt capital markets.

        If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility and the indentures governing our senior notes due 2022 (the "2022 Notes") and senior notes due 2023 (the "2023 Notes") may restrict our ability to obtain new debt financing. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, natural gas and NGLs production or reserves, and in some areas a loss of properties.

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        External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility and through the capital markets may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil, natural gas and NGLs development program, which will adversely affect the recoverability and ultimate value of our oil, natural gas and NGLs properties, in turn negatively affecting our business, financial condition and results of operations.

The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

        Approximately 42% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2015. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, continued declines in commodity prices could cause us to reevaluate our development plans and delay or cancel development. Delays in the development of our reserves, increases in costs to drill and develop such reserves or sustained periods of low commodity prices will reduce the future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves or lower commodity prices could cause us to have to reclassify our proved reserves as unproved reserves.

Our hedging strategy may be ineffective in reducing the impact of commodity price volatility from our cash flows, which could result in financial losses or could reduce our income.

        To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGLs, we enter into commodity derivative contracts for a significant portion of our oil, natural gas and NGL production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil, natural gas and NGLs. In addition, our senior secured revolving credit facility limits the aggregate notional volume of commodities that can be covered under commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. For the years ending December 31, 2016, 2017, and 2018, approximately 26%, 62%, and 71%, respectively, of our estimated total oil, natural gas and NGL production from proved reserves, based on our reserve report as of December 31, 2015, will not be covered by commodity derivative contracts.

        Our policy has been to hedge a significant portion of our estimated oil, natural gas and NGLs production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil, natural gas and NGLs prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases.

        In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we projected. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity.

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There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field.

        As a result of these factors, our commodity derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Our hedging transactions expose us to counterparty credit risk.

        Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty's liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty's creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Currently our entire hedge portfolio is hedged directly with banks in our credit agreements, thus allowing hedging without any margin requirements.

        During periods of falling commodity prices, our hedge receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Derivatives legislation and implementing rules could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate risk and other risks associated with our business.

        We use commodity derivatives to manage our commodity price risk. The U.S. Congress adopted comprehensive financial reform legislation that, among other things, expands comprehensive federal oversight and regulation of derivatives and many of the entities that participate in that market. Although the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted on July 21, 2010, the Commodity Futures Trading Commission, or the CFTC, and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to derivatives. While some of these rules have been finalized, some have not. When fully implemented, the law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties.

        In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.

Unless we replace our reserves, our reserves and production will naturally decline, which would adversely affect our business, financial condition and results of operations.

        Unless we conduct successful exploration, development and acquisition activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil, natural gas and NGL reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

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Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent or delay associated expected production. In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drilling locations.

        Our management team has identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. Similarly, the use of technologies and the study of producing fields in the same area of producing wells will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient quantities of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In addition, our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. In addition, a number of our identified drilling locations are associated with joint development agreements and if we do not meet our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to continue to develop certain acreage covered by that agreement. Because of the uncertainty inherent in these factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other drilling locations. Our initial capital budget for 2016 is $25 million. We are not currently drilling on our acreage, and there can be no assurances regarding when we will resume drilling. Unless we resume drilling such that production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire.

Continued low commodity prices or future price declines or downward reserve revisions may result in write-downs of the carrying values of our properties.

        Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Such impairment may be accompanied by a reduction in proved reserves, thereby increasing future depletion charges per unit of production. We may incur impairment charges and related reductions in proved reserves in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. If commodity prices remain low relative to their historical levels, we may incur future impairments to long-lived assets.

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Our estimated oil, natural gas and NGLs reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any significant inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

        Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves. Our estimates of our proved reserve quantities are based upon our reserve report as of December 31, 2015. Reserve estimation is a subjective process of evaluating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a reasonable time.

        The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil, natural gas and NGL prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Quantities of proved reserves are estimated based on pricing conditions in existence during the period of assessment and costs at the end of the period of assessment. Changes to oil, natural gas and NGL prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields, because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

        Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, changes in future production cost assumptions could have a significant effect on our proved reserve quantities.

If we do not fulfill our obligation to drill minimum numbers of wells specified in our joint development agreements, we will lose the right to develop the undeveloped acreage associated with the agreement and any proved undeveloped reserves attributable to such undeveloped acreage.

        If we do not meet our obligation to drill the minimum number of wells specified in a joint development agreement, we will lose the right to continue to develop the undeveloped acreage covered by the agreement, which would result in the loss of any proved undeveloped reserves attributable to such undeveloped acreage. For example, we do not currently anticipate drilling new wells on our Arkoma Woodford acreage. As a result, we will not spud the required number of additional wells per the joint development agreement between us and Vanguard Natural Resources within the prescribed time period to maintain rights to the additional future drilling locations. The loss of these drilling locations, along with other near term lease expirations in the Arkoma, have contributed to a reduction in our Woodford proved undeveloped reserve figures and total drilling location count.

The standardized measure of discounted future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated oil, natural gas and NGL reserves.

        You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil, natural gas and NGL reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the 12- month unweighted arithmetic average of the first-day-of-the-month commodities

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prices for the preceding 12 months without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

•

commodity price hedging and actual prices we receive for oil, natural gas and NGLs;

•

actual cost of development and production expenditures;

•

the amount and timing of actual development and production; and

•

changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general.

        If oil prices decline by $10.00 per Bbl, then our standardized measure as of December 31, 2015 excluding hedging impacts would decrease approximately $139.7 million holding all costs constant. If natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2015 excluding hedging impacts would decrease by approximately $101.4 million holding all costs constant.

Over 99% of our estimated proved reserves are located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, making us vulnerable to risks associated with operating in one geographic area.

        Over 99% of our estimated proved reserves as of December 31, 2015 were located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma. Approximately 79% of our 2015 production was from the Cleveland formation where properties are located in four contiguous counties of Texas and Oklahoma. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as our properties producing from the Cleveland formation, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Our customer base is concentrated, and the loss of any one of our key customers could, therefore, adversely affect our financial condition and results of operations.

        Historically, we have been dependent on a few customers for a significant portion of our revenue. For the year ended December 31, 2015 purchases by our top five customers accounted for approximately 18%, 17%, 16%, 15% and 7%, respectively, of our total oil, natural gas and NGL sales. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. To the extent that any of our major purchasers reduces their purchases of oil, natural gas or NGLs or defaults on their obligations to us, our financial condition and results of operations could be adversely affected.

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We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

        In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

        In addition, our senior secured revolving credit facility impose certain limitations on our ability to enter into mergers or combination transactions. Our senior secured revolving credit facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

        Any acquisition involves potential risks, including, among other things:

•

the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures, operating expenses and costs;

•

an inability to successfully integrate the assets we acquire;

•

an inability to obtain satisfactory title to the assets we acquire;

•

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

•

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•

the assumption of unknown liabilities, losses or costs for which we obtain no or limited indemnity or other recourse;

•

the diversion of management's attention from other business concerns;

•

an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and

•

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

        Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.

        The success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

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Deficiencies of title to our leased interests could significantly affect our financial condition.

        It is our practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk's office to determine mineral ownership before we acquire an oil and gas lease or other developed rights in a specific mineral interest.

        Prior to the drilling of an oil or gas well, it is the normal practice in our industry for the operator of the well to obtain a drilling title opinion from a qualified title attorney to ensure there are no obvious title defects on the property on which the well is to be located. The title attorney would typically research documents that are of record, including liens, taxes and all applicable contracts that burden the property. Frequently, as a result of such examinations, certain curative work must be undertaken to correct defects in the marketability of the title, and such curative work entails expense. Our failure to completely cure any title defects may invalidate our title to the subject property and adversely impact our ability in the future to increase production and reserves. Additionally, because a less strenuous title review is conducted on lands where a well has not yet been scheduled, undeveloped acreage has greater risk of title defects than developed acreage. Any title defects or defects in assignment of leasehold rights in properties in which we hold an interest may adversely impact our ability in the future to increase production and reserves, which could have a material adverse effect on our business, financial condition and results of operations.

        We conduct a substantial portion of our operations through joint development agreements with third parties. Certain of our joint development agreements include complete-to-earn arrangements, whereby we are assigned title to properties from the third-party after we complete wells and, in the case of certain counterparties, after completion reports relating to the wells have been approved by regulatory authorities whose approval may be delayed. Furthermore, certain of our joint development agreements specify that assignments are only to occur when the wells are capable of producing hydrocarbons in paying quantities. These additional conditions to assignment of title may from time to time apply to wells of substantial value. If one of our counterparties assigned title to a well in which we had earned an interest (according to our joint development agreement) to a third-party, our title to such a well could be adversely impacted. In addition, if one of our counterparties becomes a debtor in a bankruptcy proceeding, or is placed into receivership, or enters into an assignment for the benefit of creditors, after we had earned ownership of, but before we had received title to, a well, certain creditors of the counterparty may have rights in that well that would rank prior to ours.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated and new taxes may be imposed as a result of future legislation.

        From time to time, legislation is introduced that would, if enacted, make significant changes to U.S. tax laws. These proposed changes have included repealing many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposing new fees. Among others, proposed changes have included: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical cost amortization period for independent producers; imposing a per barrel fee on domestically produced oil; and implementation of a fee on non-producing federal oil and gas leases. The passage of legislation containing some or all of these provisions or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could have a material adverse effect on our business, financial condition and results of operations.

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We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

        The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of our larger competitors not only drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGL prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations.

        The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

        We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services as well as fees for the cancellation of such services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

        We utilize third-party services to maximize the efficiency of our operation. The cost of oil field services typically fluctuates based on demand for those services. We may not be able to contract for

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such services on a timely basis, or the cost of such services may not remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including hydraulic fracturing equipment, supplies and personnel necessary for horizontal drilling, could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our financial condition and results of operations.

        Our business depends in part on pipelines, transportation and gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGLs production and could harm our business.

        The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, such as trucks, gathering systems and processing facilities owned by third parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Also, the transfer of our oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to transportation options, including trucks owned by third parties, can also be affected by U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil, natural gas and NGLs production and harm our business.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

        We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

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adverse weather conditions and natural disasters;

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encountering abnormally pressured formations;

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facility or equipment malfunctions;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

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fires, explosions and ruptures of pipelines;

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personal injuries and death; and

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terrorist attacks targeting oil and natural gas related facilities and infrastructure.

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        Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage and associated clean-up responsibilities;

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regulatory investigations, penalties or other sanctions;

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suspension of our operations; and

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repair and remediation costs.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

        Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and NGLs we may produce and sell.

        We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil, natural gas and NGLs, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their ultimate effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas, NGLs or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government, and third parties and may require us to incur substantial costs for remediation.

        See "Item 1. Business—Regulations" for a further description of the laws and regulations that affect us.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

        We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

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the Clean Air Act, or CAA, and comparable state laws and regulations that impose obligations related to air emissions;

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the Clean Water Act and Oil Pollution Act, or OPA, and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

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the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

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the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;

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the Environmental Protection Agency's, or the EPA's, community right to know regulations under the Title III of CERCLA and comparable state laws that require that we organize and/or disclose information about hazardous materials used or produced in our operations;

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the Occupational Safety and Health Act, or OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

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the National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

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the Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing, or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban on operations in affected areas; and

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the Endangered Species Act, or ESA, and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species.

        We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and product transportation pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, ephemeral streams, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filing requirements. In addition, these laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where petroleum or hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including laws related to climate change and greenhouse gases, may be adopted in the future. The trend of more expensive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. We are also subject to many other environmental requirements delineated in "Business—Environmental Matters and Regulation."

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing and other oil and gas production activities as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, in states where the EPA is the permitting authority and released guidance in February 2014 on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel in those states. In addition, the EPA issued a notice of rulemaking under the Toxic Substances Control Act relating to chemical substances and mixtures used in oil and gas exploration and production. Congress has also considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

        Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas, or TRRC, and the public of certain information regarding the components of the fluids used in the hydraulic fracturing process. On December 13, 2011, the TRRC finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after February 1, 2012. In addition, on October 20, 2011, Louisiana adopted new regulations for hydraulic fracturing operations in the state. These new regulations require hydraulic fracturing operators to publicly disclose the volume of hydraulic fracturing fluid, the type, trade name, supplier and volume of additives, and a list of chemical compounds contained in the additive, along with its maximum concentration, subject to certain trade secret protections. However, trade secret chemicals must be identified by their chemical family. The mandatory disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment. In addition, the Oklahoma Corporation Commission has adopted rules prohibiting water pollution resulting from hydraulic fracturing operations and requiring disclosure of chemicals used in hydraulic fracturing.

        Texas has also authorized the Texas Commission on Environmental Quality to suspend water use rights for oil and gas users in the event of serious drought conditions and has imposed more stringent emissions, monitoring, inspection, maintenance, and repair requirements on Barnett Shale operators to minimize Volatile Organic Compound, or VOC, releases. Also, Louisiana requires operators to minimize releases of gases into the open air after hydraulic fracturing in certain urban areas.

        In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If state, local, or municipal legal restrictions are adopted in areas where we are currently conducting operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

        There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration- wide review of hydraulic fracturing practices, and a

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committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released its first progress report on this study in December 2012 and has also released several papers for public and peer review. The EPA released its draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review in June 2015.

        The EPA completed its study of wastewater resulting from hydraulic fracturing activities and, in April 2015, proposed a pretreatment standard of zero discharge, which if adopted will prohibit discharges to publicly-owned treatment works. . The EPA is also conducting a study of private wastewater treatment facilities, referred to as centralized waste treatment, or CWT, facilities, accepting oil and gas extraction wastewater and will evaluate whether to revise discharge limits from CWT facilities. In addition, the U.S. Department of Energy's Natural Gas Subcommittee of the Secretary of Energy Advisory Board conducted a review of hydraulic fracturing issues and practices and made recommendations to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. The Interagency Working Group on Unconventional Natural Gas and Oil was created by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional oil and natural gas resources.

        Also, in 2015, the U.S. Department of the Interior's Bureau of Land Management, or BLM, adopted rules regarding well stimulation, chemical disclosures and other requirements for hydraulic fracturing on federal and Indian lands; however, a federal district court has stayed the effectiveness of these BLM rules as challenges to the rules are proceeding. BLM released a proposed rule in January 2016 that would require reductions in venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Similarly, on October 26, 2015, the NPS, proposed to update its regulations governing non-federal oil and gas rights. Most notably, the NPS rulemaking would eliminate two provisions that exempt approximately 60% of the oil and gas operations located within the national park system from the requirement to obtain NPS approval of a proposed plan of operations before commencing nonfederal oil and gas operations in an NPS unit and would clarify well stimulation (including hydraulic fracturing) information requirements and operating standards.

        State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission rules allow the Commission to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. The Oklahoma Corporation Commission also asserts authority to shut down injection wells that it considers linked to induced seismicity, and has recently taken other steps to regulate injection wells that may contribute to induced seismicity. For example, on August 3, 2015, the Oklahoma Corporation Commission adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in Oklahoma. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.

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        Further, on April 17, 2012, the EPA released final rules to subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. These rules became effective on October 15, 2012. The EPA rules also include NSPS standards for completions of hydraulically-fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. In October 2012, several challenges to the EPA's rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The EPA has since reconsidered several aspects of the rules and may continue to make changes. For example in 2015, the EPA finalized a final rule defining "low pressure gas well" and removing "connected in parallel" from the definition of storage vessels in the New Source Performance Standard. Depending on the outcome of such judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA may issue new rules. We have reported some of our facilities as being subject to these rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy reporting and other administrative requirements associated with these rules. We continue to evaluate the effect these rules will have on our business. In addition, on September 18, 2015, the EPA proposed to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector as a measure to implement the Climate Action Plan. On the same day, the EPA also proposed a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes. This rule could cause small facilities, on a aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Final rules are expected in 2016. The Administration has also stated that other federal agencies, including the Bureau of Land Management, the Pipeline and Hazardous Materials Safety Administration, and the Department of Energy will impose new or more stringent regulations on the oil and gas sector that will have the effect of further reducing methane emissions. Increased regulation and attention given to the hydraulic-fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic-fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale formations, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce; and actual impacts of climate change like extreme weather conditions could adversely affect our operations.

        In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on its findings, the EPA promulgated regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one rule that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission

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sources in the United States. On November 9, 2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities with reporting of GHG emissions from such facilities required on an annual basis. The first reports were due in 2012 for emissions occurring in 2011. In 2015, the EPA added reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines to the GHG reporting rule. We are currently required to monitor and report GHG emissions under this rule, and operational and/or regulatory changes could increase the burden of compliance with GHG emissions monitoring and reporting requirements.

        The Climate Action Plan also calls for reductions of methane emissions. As previously mentioned, the federal administration has proposed a rule to require methane reductions from oil and gas sources, with a final rule expected in 2016. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. In addition, international, federal, regional and local regulatory initiatives that target GHGs could adversely affect the marketability of the oil and natural gas we produce. On October 23, 2015, the EPA published the final Clean Power Plan. While the rule directly applies to power plants, the Clean Power Plan is targeted at creating a shift from fossil fuels toward renewable power generation; however the rule has been stayed and is not effect during the judicial review. Also, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and, if it comes into force, would require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

        In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

We may face unanticipated water and other waste disposal costs.

        We may be subject to regulation that restricts our ability to discharge water produced as part of our oil or gas production operations. Productive zones frequently contain water that must be removed in order for the oil or gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil or gas in commercial quantities. The produced water currently is transported from the lease and injected into disposal wells. Some states, including Texas and Oklahoma, also assert the authority to shut down disposal wells that are deemed to contribute to induced seismicity, or seismic activity that is caused by human activity. On August 3, 2015, the Oklahoma Corporation Commission adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in

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Oklahoma. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the EPA has proposed to prohibit the disposal of wastewater from hydraulic fracturing into publicly owned treatment facilities through a "zero discharge" pretreatment standard. The EPA is also conducting a study of private wastewater treatment facilities, referred to as centralized waste treatment, or CWT, facilities, accepting oil and gas extraction wastewater and will evaluate whether to revise discharge limits from CWT facilities. Therefore, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

        In the event water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

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we cannot obtain future permits from applicable regulatory agencies;

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water of lesser quality or requiring additional treatment is produced;

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our wells produce excess water;

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new laws and regulations require water to be disposed in a different manner; or

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costs to transport the produced water to the disposal wells increase.

We conduct a substantial portion of our operations through farm-outs, areas of mutual interest and other joint development agreements. These agreements subject us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.

        We conduct a substantial portion of our operations through joint development agreements with third parties, including ExxonMobil. We may also enter into other joint development agreements in the future. These third parties may have obligations that are important to the success of the joint development agreement, such as the obligation to contribute capital or pay carried or other costs associated with the joint development agreement. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

        Our joint development agreements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

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our joint development partners may share certain approval rights over major decisions;

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our joint development partners may not pay their share of the joint development agreement obligations, leaving us liable for their share of joint development liabilities;

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we may incur liabilities as a result of an action taken by our joint development partners;

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our joint development partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

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disputes between us and our joint development partners may result in delays, litigation or operational impasses.

        The risks described above, the failure to continue our joint ventures or to resolve disagreements with our joint development partners could adversely affect our ability to transact the business of such joint development, which would in turn negatively affect our financial condition and results of operations.

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Risks Relating to Financings and Ownership:

Increases in interest rates could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive disadvantage. For example, as of December 31, 2015, we had an unused borrowing capacity of approximately $400 million under our revolving credit facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $510 million available under our revolving credit facility would result in increased annual interest expense of approximately $5.1 million and a corresponding decrease in our net income. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in our cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The borrowing base under our revolving credit facility is subject to redetermination and any reduction in the borrowing base may reduce our liquidity or result in our having to repay indebtedness under our revolving credit facility earlier than anticipated.

        The borrowing base under our revolving credit facility will be redetermined at least semi-annually on or about April 1 and October 1 of each year, with such redetermination based primarily on reserve reports using lender commodity price expectations at such time. JEH and the administrative agent (acting at the direction of lenders holding at least 66²/3% of the outstanding loans) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our material operating agreements or upon the cancellation or termination of certain of our joint development agreements. The borrowing base may also be reduced as a result of our issuance of unsecured notes, our termination of material hedging positions or our consummation of significant asset sales. If current low commodity prices continue through such redetermination events, the borrowing base under our revolving credit facility may be reduced.

        Certain federal regulatory agencies, including the Office of the Comptroller of the Currency (OCC), the Federal Reserve, and the Federal Deposit Insurance Corp., have recently focused on oil and gas lenders' examinations and ratings of reserve-based loans, with a view towards encouraging such lenders to reduce their exposure to potentially substandard loans to oil and gas companies. In April 2014, the OCC issued the "Oil and Gas Production Lending" bank examination booklet, which details potential regulatory requirements related to reserve-based lending. Whether or not these regulatory agencies are successful in implementing stricter requirements related to reserve-based lending, oil and gas lenders may respond to these discussions by taking a more conservative approach in their lending practices, which could adversely impact future borrowing base redeterminations under our revolving credit facility.

        Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities."

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The Jones family and Metalmark Capital, our primary private equity investor, control a significant percentage of Jones Energy, Inc.'s voting power and have the ability to take actions that may conflict with your interests.

        As of December 31, 2015, the Jones family and Metalmark Capital held approximately 51.3% of the combined voting power of Jones Energy, Inc. Although the Jones family and Metalmark Capital are entitled to act separately in their own respective interests with respect to their ownership interests in Jones Energy, Inc., the Jones family and Metalmark Capital will have the ability to elect all of the members of our board of directors, and thereby control our management and affairs. In addition, the Jones family and Metalmark Capital have significant influence over all matters that require approval by our stockholders, including mergers and other material transactions.

The loss of senior management or technical personnel could adversely affect our operations.

        Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain insurance against the loss of any of these individuals. Our business will also be dependent upon our ability to attract and retain qualified personnel. Since the fourth quarter of 2014, the prices of oil, natural gas and NGLs were extremely volatile and declined significantly. Key employees may depart because of uncertainty during times of commodity price volatility. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud.

        Over time, we have had limited accounting personnel to execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment to ensure that the design and execution of our controls has consistently resulted in effective review of our financial statements and supervision by appropriate individuals. As a result of these factors, certain material misstatements in our annual financial statements were discovered and brought to the attention of our management by our independent registered public accounting firm for correction. These material misstatements were the result of a combination of control deficiencies which we concluded constituted a material weakness in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

        Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded company. To comply with the requirements of being a publicly traded company, we may need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance, tax and legal staff. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. If one or more material weaknesses persist or if we fail to establish

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and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. Ineffective internal controls could also subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business.

For as long as we are an emerging growth company, we will not be required to comply with certain requirements that apply to other public companies.

        We continue to qualify as an "emerging growth company" under the Jumpstart Our Business Startups Act (the "JOBS Act"). By virtue of such, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non- convertible debt over a three-year period.

        To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

        The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and distribution activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation and process and record financial and operating data. As an oil and natural gas producer, we face various security threats, including cyber-security threats. Cyber-security attacks in particular are increasing and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although to date we have not experienced any material losses related to cyber-security attacks, we may suffer such losses in the future. Moreover, the various procedures and controls we use to monitor and protect against these threats and to mitigate our exposure to such threats may not be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

Loss of our information and computer systems could adversely affect our business.

        We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, natural gas and NGLs and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

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We will incur corporate income tax liabilities on taxable income allocated to us by JEH with respect to JEH Units we own, which may be substantial. JEH is required to make cash tax distributions under its operating agreement. Our ability to make tax distributions, and pay taxes and the TRA liability may be limited by our structure and available liquidity. To the extent that we incur cash income tax liabilities or are required to make cash tax distributions and cash payments of the TRA liability it would impact our liquidity and reduce cash available for other uses.

        We are not drilling new wells at this time, which limits our planned capital spending. As a result of this, our tax deductions associated with intangible drilling costs would be significantly lower, reducing our ability to offset our taxable income. Further, considering the recognition of income associated with debt extinguishment by JEH, we are likely to be allocated taxable income in excess of any such tax deductions relating to 2016. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook" and Note 15, "Subsequent Events," in the Notes to Consolidated Financial Statements for further discussion of these items. Under the terms of its operating agreement, JEH is generally required to make quarterly pro rata cash tax distributions to its unitholders (including us) based on income allocated to such unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions described below. Based on our 2016 budget and debt extinguishment through February 29, 2016, we estimate that the amount of tax distributions to JEH unitholders (other than us), plus the amount of our cash tax liabilities, in 2016 would be approximately $38.3 million based on information available as of this filing. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors. Additional debt extinguishment during the remainder of 2016 would increase the amount of potential tax payments to JEH unitholders (other than us) and the amount of our cash tax liabilities, whereas a decision to deploy capital to drill new wells would decrease the amount of any potential tax distributions and liabilities.

        We are classified as a corporation for U.S. federal income tax purposes and, in most states in which JEH does business, for state income tax purposes. Under current law, we will be subject to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state, on the net income allocated to us by JEH with respect to the JEH Units we own. We are a holding company with our sole asset consisting of our ownership in JEH and have no independent means of generating revenue. JEH is classified as a partnership for federal income tax purposes and as such is not subject to federal income tax (other than as a withholding agent). Instead, taxable income is allocated to holders of JEH Units, including the JEH Units we own. Under the terms of its operating agreement, JEH is obligated to make tax distributions to holders of its units, including us, subject to the conditions described below. Our ability to cause JEH to make tax distributions, which generally will be pro rata with respect to all outstanding JEH Units, in an amount sufficient to allow us to pay our taxes and make any payments due under the TRA, is subject to various factors, including the cash requirements and financial condition of JEH, compliance by JEH or its subsidiaries with restrictions, covenants and financial ratios related to existing or future indebtedness, including under our notes and our revolving credit agreement, and other agreements entered into with third parties. As a result, it is possible that Jones Energy, Inc. will not have sufficient cash to pay taxes and make payments under the TRA liability.

        See "Risk Factors—We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may receive (or be deemed to receive), and the amounts of such payments could be significant."

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We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may receive (or be deemed to receive), and the amounts of such payments could be significant.

        We entered into the Tax Receivable Agreement with JEH and the pre-IPO owners. This agreement generally provides for the payment by us of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) as a result of (i) the tax basis increases resulting from the pre-IPO owners' exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units to us for cash) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

        The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of JEH. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. Any payments are made within a designated period of time following the filing of the tax return where we utilize such tax benefits to reduce taxes in a given year. The term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.

        The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of JEH Units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.

        The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either JEH or us.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

        If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have sufficient taxable income to fully utilize such benefits and that any JEH Units that the pre-IPO Owners or their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations.

        Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any

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payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any pre-IPO Owner will be netted against payments otherwise to be made, if any, to such pre-IPO owner after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

Item 1B.    Unresolved Staff Comments

        None.

Item 2.    Properties

        The information required by Item 2. is contained in Item 1. Business.

Item 3.    Legal Proceedings

        We are from time to time subject to, and are presently involved in, litigation or other legal proceedings arising out of the ordinary course of business. None of these legal proceedings are expected to have a material adverse effect on our financial condition, results of operations or cash flow. With respect to these proceedings, our management believes that we will either prevail, have adequate insurance coverage or have established appropriate reserves to cover potential liabilities. Any costs that management estimates may be paid related to these proceedings or claims are accrued when the liability is considered probable and the amount can be reasonably estimated. There can be no assurance, however, as to the ultimate outcome of any of these matters, and if all or substantially all of these legal proceedings were to be determined adversely to us, there could be a material adverse effect on our financial condition, results of operations and cash flow.

Items 4.    Mine Safety Disclosures

        Not applicable.

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Part II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

        Our common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "JONE."

        The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE for the periods indicated.

	2015				2014
	High		Low		High		Low
1st Quarter	$	12.60	$	7.74	$	18.32	$	13.05
2nd Quarter	$	11.63	$	8.39	$	20.57	$	14.50
3rd Quarter(1)	$	9.15	$	4.41	$	20.79	$	17.26
4th Quarter	$	6.05	$	3.20	$	18.82	$	9.50

(1)

For the third quarter of 2013, the data represents the period from July 24, 2013, the date on which our common stock began trading on the NYSE, through September 30, 2013.

        On February 29, 2016, the last sale price of our common stock, as reported on the NYSE, was $1.50 per share. As of February 29, 2016, there were 30,550,907 shares of Class A common stock outstanding held by approximately eight stockholders of record and 31,273,130 shares of Class B common stock outstanding held by approximately eleven stockholders of record.

Dividend Policy

        We have not paid any dividends and do not anticipate declaring or paying any cash dividends to holders of our Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our senior secured revolving credit facility, the 2022 Notes and the 2023 Notes prohibit us from paying dividends.

Issuer Purchases of Equity Securities

        None.

Sales of Unregistered Equity Securities

        None.

Stock Performance Graph

        The following stock performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Securities Exchange Act of 1934, as amended (the "Exchange Act"), except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.

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        The graph compares the cumulative total shareholder return to Jones Energy, Inc.'s common stockholders as compared to the cumulative total returns on the Standard & Poor's 500 index ("the S&P 500 Index") and the Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P 500 O&G E&P Index") since the time of our IPO. The graph was prepared assuming $100 was invested in our common stock at its initial public offering price of $15.00 per share and invested in the S&P 500 Index and the S&P 500 O&G E&P Index on July 24, 2013 at the closing price on such date and tracked through December 31, 2015.

Securities Authorized for issuance Under Equity Compensation Plans

        The following table presents the securities authorized for issuance under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the "LTIP") as of December 31, 2015.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights ($)		Number of Shares Remaining Available for Future Issuance under Equity Compensation Plans
Equity compensation plan approved by security holders(1)		—		—		2,303,615	(2)
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		2,303,615

(1)

Our 2013 Omnibus Incentive Plan (the "LTIP") was approved by our board of directors in July 2013 and took effect on July 29, 2013. The LTIP was also approved by our shareholders at the Annual Meeting of Shareholders on July 10, 2013.

(2)

The LTIP may consist of the following components: restricted stock, stock options, performance awards, restricted stock units, bonus stock awards, stock appreciation rights, cash awards, dividend equivalents, and other share- based awards. The LTIP limits the number of shares that may be delivered pursuant to awards to 3,850,000 shares of our Class A common stock. Our board of directors had approved total cumulative awards of 1,546,385 shares of restricted Class A common stock under the LTIP as of December 31, 2015, net of forfeitures and other adjustments that return previously awarded shares to the pool of remaining available shares.

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Item 6.    Selected Financial Data

        The following table sets forth selected financial data of Jones Energy, Inc. and its predecessor for the years ended December 31, 2015, 2014, 2013, 2012 and 2011. This information should be read in connection with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of

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Operations" and "Item 8. Financial Statements and Supplementary Data" presented elsewhere in this report.

	Year Ended December 31,
(in thousands except per share data)	2015			2014			2013			2012			2011
Operating revenues
Oil and gas sales	$	194,555		$	378,401		$	258,063		$	148,967		$	167,261
Other revenues		2,844			2,196			1,106			847			1,022
Total operating revenues		197,399			380,597			259,169			149,814			168,283
Operating costs and expenses
Lease operating		41,027			37,760			25,129			22,151			20,860
Production taxes		12,130			22,556			15,517			6,529			6,021
Exploration		6,551			3,453			16,125			356			780
Depletion, depreciation and amortization		205,498			181,669			114,136			80,709			68,906
Impairment of oil and gas properties		—			—			—			18,821			31,970
Accretion of ARO liability		1,087			770			608			533			413
General and administrative		33,388			25,763			31,902			15,875			16,679
Other operating		4,188			—			—			—			—
Total operating expenses		303,869			271,971			203,417			144,974			145,629
Operating income (loss)		(106,470	)		108,626			55,752			4,840			22,654
Other income (expense)
Interest expense		(61,289	)		(38,805	)		(27,409	)		(21,177	)		(18,704	)
Net gain (loss) on commodity derivatives		158,753			189,641			(2,566	)		16,684			34,490
Gain on bargain purchase		—			—			—			—			26,208
Other income (expense)		(2,852	)		(7,624	)		(3,443	)		(2,953	)		(4,149	)
Other income (expense), net		94,612			143,212			(33,418	)		(7,446	)		37,845
Income (loss) before income tax		(11,858	)		251,838			22,334			(2,606	)		60,499
Income tax provision
Current		111			53			85			—			—
Deferred		(2,892	)		26,165			(156	)		473			173
Total income tax provision (benefit)		(2,781	)		26,218			(71	)		473			173
Net income (loss)		(9,077	)		225,620			22,405			(3,079	)		60,326
Net income (loss) attributable to non-controlling interests		(6,696	)		184,484			24,591			—			—
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136		$	(2,186	)	$	(3,079	)	$	60,326
Earnings per share:
Basic	$	(0.09	)	$	3.28		$	(0.17	)
Diluted	$	(0.09	)	$	3.28		$	(0.17	)
Weighted average shares outstanding:
Basic		26,816			12,526			12,500
Diluted		26,816			12,535			12,500
Other Supplementary Data:
EBITDAX(1)	$	268,417		$	303,014		$	204,997		$	135,741		$	127,960
Adjusted net income(2)	$	2,220		$	68,824		$	56,425		$	29,767		$	35,674

(1)

EBITDAX is a non-GAAP financial measure. For a definition of EBITDAX and a reconciliation of EBITDAX to our net income, see "—Non-GAAP Financial Measures" below.

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(2)

Adjusted net income is a non-GAAP financial measure. For a definition of adjusted net income and a reconciliation of adjusted net income to our net income, see "—Non-GAAP Financial Measures" below.

	Year Ended December 31,
(in thousands of dollars)	2015			2014			2013			2012			2011
Statement of Cash Flow Data
Net cash flow provided by operating activities	$	69,030		$	265,423		$	148,573		$	84,550		$	120,217
Net cash used in investing activities		(168,401	)		(463,903	)		(368,277	)		(337,636	)		(318,963	)
Net cash provided by financing activities		107,698			188,226			219,798			270,676			186,322
Net increase (decrease) in cash	$	8,327		$	(10,254	)	$	94		$	17,590		$	(12,424	)

	As of December 31,
(in thousands of dollars)	2015		2014		2013		2012		2011
Balance Sheet Data
Cash and cash equivalents	$	21,893	$	13,566	$	23,820	$	23,726	$	6,136
Other current assets		172,611		230,797		121,770		74,886		88,546
Total current assets		194,504		244,363		145,590		98,612		94,682
Property and equipment, net		1,639,639		1,642,908		1,300,672		1,010,742		743,575
Other long-term assets		111,269		107,578		41,717		41,332		42,878
Total assets		1,945,412	$	1,994,849	$	1,487,979	$	1,150,686	$	881,135
Current liabilities	$	67,906	$	229,281	$	179,668	$	93,360	$	108,440
Long-term debt		847,912		860,000		658,000		610,000		415,000
Other long-term liabilities		92,742		52,218		26,187		18,926		11,787
Total stockholders' / members' equity		936,852		853,350		624,124		428,400		345,908
Total liabilities and stockholders' / members' equity		1,945,412	$	1,994,849	$	1,487,979	$	1,150,686	$	881,135

Non-GAAP financial measures

        EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

        We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other items described below. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's

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financial performance, such as a company's cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

        The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to EBITDAX for the periods indicated:

	Year Ended December 31,
(in thousands of dollars)	2015			2014			2013			2012			2011
Reconciliation of EBITDAX to net income
Net income (loss)	$	(9,077	)	$	225,620		$	22,405		$	(3,079	)	$	60,326
Interest expense		61,289			38,805			27,409			21,177			18,704
Exploration expense		6,551			3,453			16,125			356			780
Income taxes		(2,781	)		26,218			(71	)		473			173
Amortization of deferred financing costs		3,169			3,070			2,644			3,511			2,907
Depreciation and depletion		205,498			181,669			114,136			80,709			68,906
Impairment of oil and natural gas properties		—			—			—			18,821			31,970
Accretion of ARO liability		1,087			770			608			533			413
Reduction of TRA liability		(1,984	)		—			—			—			—
Other non-cash charges		1,023			376			79			129			(59	)
Stock compensation expense		7,562			4,040			10,838			570			1,134
Other compensation expense		455			758			2,719			—			—
Net (gain) loss on derivative contracts		(158,753	)		(189,641	)		2,566			(16,684	)		(34,490	)
Current period settlements of matured derivative contracts		149,801			4,476			5,209			29,783			2,162
Amortization of deferred revenue		(1,960	)		(1,154	)		(469	)		—			—
Gain on bargain purchase		—			—			—			—			(26,208	)
(Gain) loss on sale of assets		3			(297	)		78			(1,162	)		859
Stand-by rig costs		4,188			—			—			—			—
Financing expenses and other loan fees		2,346			4,851			721			604			383
EBITDAX	$	268,417		$	303,014		$	204,997		$	135,741		$	127,960

        Adjusted Net Income and Adjusted Earnings per Share are supplemental non- GAAP financial measures that are used by management and external users of the Company's consolidated financial statements. We define Adjusted Net Income as net income excluding the impact of certain non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, non-cash compensation expense, and the other items described below. We define Adjusted Earnings per Share as earnings per share plus that portion of the components of adjusted net income allocated to the controlling interests divided by weighted average shares outstanding. We believe adjusted net income and adjusted earnings per share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Our computations of adjusted net income and adjusted earnings per share may not be comparable to other similarly titled measures of other companies.

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        The following table provides a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated.

	Year Ended December 31,
(in thousands except per share data)	2015			2014			2013			2012			2011
Net income (loss)	$	(9,077	)	$	225,620		$	22,405		$	(3,079	)	$	60,326
Net (gain) loss on derivative contracts		(158,753	)		(189,641	)		2,566			(16,684	)		(34,490	)
Current period settlements of matured derivative contracts		149,801			4,476			5,209			29,783			2,162
Impairment of oil and gas properties		—			—			—			18,821			31,970
Exploration		6,551			3,453			16,125			356			780
Non-cash stock compensation expense		7,562			4,040			10,838			570			1,134
Other non-cash compensation expense		455			758			2,719			—			—
Gain on bargain purchase		—			—			—			—			(26,208	)
Stand-by rig costs		4,188			—			—			—			—
Financing expenses		2,250			3,761			—			—			—
Reduction of TRA liability		(1,984	)		—			—			—			—
Tax impact of adjusting items(1)		(1,106	)		16,357			(3,437	)		—			—
Change in valuation allowance		2,333			—			—			—			—
Adjusted net income		2,220			68,824			56,425		$	29,767		$	35,674
Adjusted net income attributable to non-controlling interests		1,275			56,208			52,679
Adjusted net income attributable to controlling interests		945			12,616			3,746
Earnings per share (basic and diluted)	$	(0.09	)	$	3.28		$	(0.17	)
Net (gain) loss on derivative contracts		(2.68	)		(3.85	)		0.43
Current period settlements of matured derivative contracts		2.48			0.09			(0.01	)
Exploration		0.12			0.07			0.31
Non-cash stock compensation expense		0.13			0.08			0.02
Other non-cash compensation expense		0.01			0.02			—
Stand-by rig costs		0.06			—			—
Financing expenses		0.03			0.08			—
Reduction of TRA liability		(0.07	)		—			—
Tax impact of adjusting items(1)		(0.04	)		1.24			(0.28	)
Change in valuation allowance		0.09			—			—
Adjusted earnings per share (basic and diluted)	$	0.04		$	1.01		$	0.30
Effective tax rate on net income attributable to controlling interests		38.9	%		35.7	%		36.9	%

(1)

In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains "forward-looking statements" that are based on management's current expectations, estimates and projections about our business and operations, and that involve risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under "Risk Factors," "Cautionary Statement Regarding Forward- Looking Statements" and elsewhere in this report.

Overview

        Jones Energy, Inc. is an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States. The Company's assets are located within the Anadarko and Arkoma basins of Texas and Oklahoma, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas. We have drilled 827 total wells, including over 650 horizontal wells, since our formation. We optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we believe we are recognized as one of the lowest-cost drilling and completion operators in the Cleveland and Woodford shale formations.

        As of December 31, 2015, our total estimated proved reserves were 101.7 MMBoe, of which 58% were classified as proved developed reserves. Approximately 25% of our total estimated proved reserves as of December 31, 2015 consisted of oil, 32% consisted of NGLs, and 43% consisted of natural gas.

Outlook

        The markets for oil, natural gas and NGLs, historically, have been volatile. During late 2014 and 2015, the oil and natural gas industry experienced a significant decline in commodity prices. As an example, during 2015, the NYMEX WTI oil price ranged from a high of approximately $61 per Bbl to a low of approximately $35 per Bbl, the lowest price since 2009, and the average daily price for NYMEX Henry Hub natural gas reached a low of $1.63 per MMBtu in December, the lowest price since 1999. Depressed commodity prices have continued into 2016, and historically low commodity prices may exist for an extended period. The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. These markets will likely continue to be volatile in the future.

        We believe that the commodity pricing environment will remain challenging for our business in 2016. However, we believe that our strong hedge position, our ability to further reduce drilling and completion costs, and our existing drilling inventory of 2,103 gross drilling locations will enable us to compete for strategic acquisitions and joint development opportunities, and if commodity prices rise in the future to generate attractive economic rates of return from the development of our inventory of drilling locations.

        The estimated mark-to-market value of our commodity price hedges in 2016 and beyond was approximately $261 million incorporating strip pricing as of February 29, 2016. We engage in derivative risk management activities in order to reduce the risk associated with commodity price fluctuations. Commodity hedges in place for 2016 will help mitigate some of the commodity price volatility and

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recent declines. The following table summarizes our commodity derivative contracts outstanding as of February 29, 2016:

	Fiscal Year Ending December 31,
	2016		2017		2018		1H19
Oil, Natural Gas and NGL Swaps
Oil (MBbl)		1,419		1,004		803		339
Natural Gas (MMcf)		16,470		12,300		10,240		4,410
Ethane (MBbl)		53		—		—		—
Propane (MBbl)		627		—		—		—
Iso Butane (MBbl)		76		7		—		—
Butane (MBbl)		218		17		—		—
Natural Gasoline (MBbl)		227		18		—		—
Total NGLs (MBbl)		1,201		42		—		—
Weighted Average Prices
Oil ($ / Bbl)	$	99.87	$	80.01	$	77.47	$	64.65
Natural Gas ($ / Mcf)	$	4.49	$	4.29	$	4.19	$	3.53
Ethane ($ / Gal)	$	0.21		—		—		—
Propane ($ / Gal)	$	0.55		—		—		—
Iso Butane ($ / Gal)	$	0.75	$	1.42		—		—
Butane ($ / Gal)	$	0.72	$	1.37		—		—
Natural Gasoline ($ / Gal)	$	1.46	$	1.73		—		—

        Sustained downward pressure on commodity prices has adverse effects on our business and financial position. Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the global oversupply situation could have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.

        The amount of our proved reserves, as estimated based on SEC pricing and definitions, was 101.7 MMBoe as of December 31, 2015, of which 58% were classified as proved developed reserves. This decrease of approximately 12%, from 115.3 MMBoe as of December 31, 2014, was primarily due to the decline in commodity prices.

        The Company reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.

        Periodic revisions to the estimated reserves and related future cash flows may be necessary as a result of a number of factors, including changes in oil and natural gas prices, reservoir performance, new drilling and completion, purchases, sales and terminations of leases, drilling and operating cost changes, technological advances, new geological or geophysical data or other economic factors. All of these factors are inherently estimates and are inter-dependent. While each variable carries its own degree of uncertainty, some factors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are

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ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, as such revisions could be negatively impacted by:

•

Declines in commodity prices or actual realized prices below those assumed for future years;

•

Increases in service costs;

•

Increases in future global or regional production or decreases in demand;

•

Increases in operating costs;

•

Reductions in availability of drilling, completion, or other equipment.

        If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. Any future impairments are difficult to predict, and although it is not reasonably practicable to quantify the impact of any future impairments at this time, such impairments may be significant.

        Our 2015 capital expenditures totaled $200.1 million excluding the impact of asset retirement costs, of which $173.2 million was utilized to drill and complete operated wells. We currently plan to invest approximately $25.0 million in total capital expenditures in 2016, with the majority dedicated to workovers on existing wells and field optimization activities. We will continue to monitor market conditions and may decide at a later date to spend additional funds for a variety of opportunities which may include redeploying rigs to resume drilling activities or leasing. We are continuing to negotiate with vendors regarding service costs and do not plan on resuming its drilling program until well costs create acceptable rates of return at strip prices. Please see "Liquidity and Capital Resources." Assuming current market conditions and drilling success rates comparable to our historical performance, we believe we will be able to fund all of our 2016 budgeted capital expenditures with our cash flow from operations. Furthermore, all drilling locations classified as proved undeveloped reserves in the year-end reserve report are scheduled to be drilled within five years of initial proved reserve booking. In order to accomplish this, our capital expenditure budgets in future years are expected to increase significantly as compared with the current 2016 budget.

        In January and February 2016, through several open market and privately negotiated purchases, we purchased an aggregate principal amount of $170.5 million of our senior unsecured notes. As of February 29, 2016, we had purchased $70.5 million principal amount of our 2022 Notes for $27.1 million, and $100 million principal amount of our 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. We used cash on hand and borrowings under our Revolver (as defined below) to fund the note purchases. As a result of these purchases, we had an aggregate principal amount of senior unsecured notes outstanding of $579.5 million, outstanding borrowings under our Revolver of $185 million, $325 million undrawn on our revolving credit facility, and $46 million in cash as of February 29, 2016. In conjunction with the extinguishment of this debt, JEH LLC recognized cancellation of debt income of $90.7 million on a pre-tax basis.

        We may from time to time repurchase additional debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in the open market, in privately negotiated transactions, or otherwise. Any such repurchase or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors.

        We are not drilling new wells at this time, which limits our planned capital spending to approximately $25.0 million. As a result of this, our tax deductions associated with intangible drilling costs would be significantly lower, reducing our ability to offset our taxable income. Further, considering the recognition of income associated with debt extinguishment by JEH, described above, we are likely to be allocated taxable income in excess of any such tax deductions relating to 2016. Under the terms of its operating agreement, JEH is generally required to make quarterly pro rata cash tax

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distributions to its unitholders (including us) based on income allocated to such unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on the estimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate of federal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefit of the deduction for any state taxes.

        Based on our 2016 budget and debt extinguishment through February 29, 2016, we estimate that the amount of tax distributions to JEH unitholders (other than us), plus the amount of our cash tax liabilities, in 2016 would be approximately $38.3 million based on information available as of this filing. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors. Additional debt extinguishment during the remainder of 2016 would increase the amount of potential tax distributions to JEH unitholders (other than us) and the amount of our cash tax liabilities, whereas a decision to deploy capital to drill new wells would decrease the amount of any potential tax distributions and liabilities.

Basis of Presentation

        We consider and report all of our operations as one segment.

Sources of our revenues

        We derive our revenue from the production and sale of oil, natural gas and NGLs. Our revenues are a function of oil, natural gas, and NGL production volumes sold and average sales prices received for those volumes. We recognize revenues when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. Our revenues do not include the effects of our hedging activities and may vary substantially from period to period as a result of changes in production volumes or commodity prices.

Hedging

        Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments such as swaps to hedge price risk associated with a significant portion of our anticipated oil, natural gas and NGL production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in oil and gas prices, and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. The only counterparties to our derivatives are lenders under the Revolver, and our hedge positions are generally reviewed on a monthly basis. This eliminates potential margin calls in execution and limits our credit exposure to these particular lenders. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in net income. We record such derivative instruments as assets or liabilities in the balance sheet. During the year ended December 31, 2015, 81% of our total production for oil, natural gas and NGLs was hedged. As of December 31, 2015, approximately 55% of our total forecasted production from proved reserves through 2017 was hedged, and the market value of our hedge position was $217.5 million. We do not anticipate any substantial changes in our hedging policy.

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        Our open positions as of December 31, 2015 were as follows:

	Year Ending December 31,
	2016			2017		2018		2019		2020
Oil positions(1):
Swaps:
Hedged volume (MBbl)		1,897			1,040		803		339		—
Weighted average price ($/Bbl)	$	82.74		$	78.69	$	77.47	$	64.65		—
Natural gas positions(2):
Swaps:
Hedged volume (MMcf)		16,850			12,300		10,240		4,410		—
Weighted average price ($/Mcf)	$	4.44		$	4.29	$	4.19	$	3.53		—
NGL positions(3):
Swaps:
Hedged volume (MBbl)		1,201			42		—		—		—
Weighted average price ($/gal)	$	0.75		$	1.53		—		—		—
Natural Gas Basis positions(4):
Swaps:
Hedged volume (MMcf)		16,330			—		—		—		—
Weighted average price ($/Mcf)	$	(0.18	)		—		—		—		—

(1)

The oil derivatives are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

(2)

The natural gas derivatives are settled based on the NYMEX natural gas futures price for the calculation period.

(3)

The NGL derivatives are settled based on the month's average daily price of Mont Belvieu and Conway ethane, propane, isobutane, butane and natural gasoline.

(4)

The basis swap derivatives are settled based on the differential between the NYMEX natural gas futures price and the ANR Pipeline Co. Oklahoma price, the CenterPoint Energy Gas Transmission Co. East price, the Natural Gas Pipeline Co. of America Texok zone price, the Northern Natural Gas Co. demarcation price or the Panhandle Eastern Pipe Line Co. Texas/Oklahoma price.

Principal components of our cost structure

        Lease operating expenses.    These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and gas properties. Lease operating expenses include both a portion of costs that are fixed in nature, such as infrastructure costs, as well as variable costs resulting from additional well maintenance and production enhancements. As production increases, our average lease operating expense per barrel of oil equivalent is typically reduced because fixed costs do not increase proportionately with production.

        Exploration.    Exploration expense consists of geological and geophysical costs, seismic costs, amortization of unproved leasehold costs, and the costs to drill exploratory wells that do not find proved reserves.

        Depreciation, depletion and amortization.    Under the successful efforts accounting method that we employ, we capitalize all costs associated with our acquisition, successful exploration, and all development efforts within cost centers classified by producing field. We then systematically expense the

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costs in each field on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; and (ii) the estimated plugging and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to our pipelines and other fixed assets over the estimated useful lives.

        Impairment of oil and gas properties.    This is the cost to reduce the carrying value of each field of proved and unproved oil and gas properties to no more than the fair value of the particular field for which impairment recognition is required. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.

        Accretion of ARO liability .    Accretion of ARO liabilities are related to our obligation for retirement of oil and gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity.

        General and administrative.    These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services and legal compliance.

        Interest.    The primary component of this line item is the interest paid to lenders. We finance a portion of our working capital requirements and capital expenditures with borrowings under our senior secured revolving credit facility and senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

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Results of Operations

        The following table summarizes our revenues, expenses and production data for the periods indicated.

	Years Ended December 31,									Years Ended December 31,
(in thousands of dollars except for production, sales price and average cost data)	2015			2014			Change			2014			2013			Change
Revenues:
Oil	$	114,029		$	220,090		$	(106,061	)	$	220,090		$	145,146		$	74,944
Natural gas		45,558			82,947			(37,389	)		82,947			55,511			27,436
NGLs		34,968			75,364			(40,396	)		75,364			57,406			17,958
Total oil and gas		194,555			378,401			(183,846	)		378,401			258,063			120,338
Other		2,844			2,196			648			2,196			1,106			1,090
Total operating revenues		197,399			380,597			(183,198	)		380,597			259,169			121,428
Costs and expenses:
Lease operating		41,027			37,760			3,267			37,760			25,129			12,631
Production taxes		12,130			22,556			(10,426	)		22,556			15,517			7,039
Exploration		6,551			3,453			3,098			3,453			16,125			(12,672	)
Depletion, depreciation and amortization		205,498			181,669			23,829			181,669			114,136			67,533
Accretion of ARO liability		1,087			770			317			770			608			162
General and administrative		33,388			25,763			7,625			25,763			31,902			(6,139	)
Other operating		4,188			—			4,188			—			—			—
Total costs and expenses		303,869			271,971			31,898			271,971			203,417			68,554
Operating income (loss)		(106,470	)		108,626			(215,096	)		108,626			55,752			52,874
Other income (expenses):
Interest expense		(61,289	)		(38,805	)		(22,484	)		(38,805	)		(27,409	)		(11,396	)
Net gain (loss) on commodity derivatives		158,753			189,641			(30,888	)		189,641			(2,566	)		192,207
Other income (expense)		(2,852	)		(7,624	)		4,772			(7,624	)		(3,443	)		(4,181	)
Total other income (expense)		94,612			143,212			(48,600	)		143,212			(33,418	)		176,630
Income (loss) before income tax		(11,858	)		251,838			(263,696	)		251,838			22,334			229,504
Income tax provision (benefit)		(2,781	)		26,218			(28,999	)		26,218			(71	)		26,289
Net income (loss)		(9,077	)		225,620			(234,697	)		225,620			22,405			203,215
Net income attributable to non-controlling interests		(6,696	)		184,484			(191,180	)		184,484			24,591			159,893
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136		$	(43,517	)	$	41,136		$	(2,186	)	$	43,322
Net production volumes:
Oil (MBbls)		2,583			2,475			108			2,475			1,557			918
Natural gas (MMcf)		23,839			21,922			1,917			21,922			17,575			4,347
NGLs (MBbls)		2,618			2,345			273			2,345			1,724			621
Total (MBoe)		9,174			8,474			701			8,474			6,210			2,264
Average net (Boe/d)		25,134			23,216			1,918			23,216			17,014			6,202
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	44.15		$	88.93		$	(44.78	)	$	88.93		$	93.22		$	(4.29	)
Natural gas (per Mcf), unhedged		1.91			3.78			(1.87	)		3.78			3.16			0.62
NGLs (per Bbl), unhedged		13.36			32.14			(18.78	)		32.14			33.30			(1.16	)
Combined (per Boe), unhedged		21.21			44.65			(23.44	)		44.65			41.56			3.09
Average sales price, hedged:
Oil (per Bbl), hedged	$	76.35		$	88.16		$	(11.81	)	$	88.16		$	87.86		$	0.30
Natural gas (per Mcf), hedged		3.35			4.02			(0.67	)		4.02			3.93			0.09
NGLs (per Bbl), hedged		25.73			32.60			(6.87	)		32.60			33.26			(0.66	)
Combined (per Boe), hedged		37.54			45.18			(7.64	)		45.18			42.40			2.78
Average costs (per BOE):
Lease operating	$	4.47		$	4.46		$	0.01		$	4.46		$	4.05		$	0.41
Production and ad valorem taxes		1.32			2.66			(1.34	)		2.66			2.50			0.16
Depletion, depreciation and amortization		22.40			21.44			0.96			21.44			18.38			3.06
General and administrative		3.64			3.04			0.60			3.04			5.14			(2.10	)

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Results of Operations—Year ended December 31, 2015 as compared to year ended December 31, 2014

Operating revenues

        Oil and gas sales.    Oil and gas sales decreased by $183.8 million (48.6%) to $194.6 million for the year ended December 31, 2015, as compared to $378.4 million for the year ended December 31, 2014. The decrease was attributable to the decline in commodity prices ($195.9 million), partially offset by increased production volumes ($12.1 million). The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $88.93 per Bbl to $44.15 per Bbl, or 50.4%, year over year. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $3.78 per Mcf to $1.91 per Mcf, or 49.5%, year over year. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $32.14 per Bbl to $13.36 per Bbl, or 58.4%, year over year. Average daily production increased 8.3% to 25,134 Boe per day for the year ended December 31, 2015 as compared to 23,216 Boe per day for the year ended December 31, 2014. Crude oil production increased 4.4% from 2,475 MBbls for the year ended December 31, 2014 to 2,583 MBbls for the year ended December 31, 2015. Natural gas production increased 8.7% from 21,922 MMcf for the year ended December 31, 2014 to 23,839 MMcf for the year ended December 31, 2015. The increase in production was driven by the year-over-year increase in producing wells due to continued drilling activity through the third quarter, as well as changes in completion techniques.

Costs and expenses

        Lease operating.    Lease operating expense increased by $3.2 million (8.5%) to $41.0 million for the year ended December 31, 2015, as compared to $37.8 million for the year ended December 31, 2014. The increase occurred primarily in correlation with the 8.3% increase in production volumes and number of producing wells. On a per unit basis, lease operating expense increased by $0.01 per Boe or 0.2%, from $4.46 for the year ended December 31, 2014 to $4.47 per Boe, as compared to the year ended December 31, 2015.

        Production and ad valorem taxes.    Production and ad valorem taxes decreased by $10.5 million (46.5%) to $12.1 million for the year ended December 31, 2015, as compared to $22.6 million for the year ended December 31, 2014. Overall production and ad valorem taxes decreased in conjunction with the 48.6% decrease in oil and gas revenue. Estimated ad valorem taxes accounted for $2.5 million of the decrease from $6.1 million for the year ended December 31, 2014 to $3.6 million for the year ended December 31, 2015, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes remained consistent at 4.4% for the years ended December 31, 2014 and 2015. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time.

        Exploration.    Exploration expense increased from $3.5 million for the year ended December 31, 2014 to $6.6 million for the year ended December 31, 2015. In 2015, the Company recognized charges for lease abandonment of $5.3 million relating to certain leases that the Company does not plan to develop. In 2014, the Company recognized the drilling cost of $3.0 million associated with an unsuccessful exploratory well. The remaining spend during 2015 primarily related to geological data and seismic processing associated with unproved acreage.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization increased by $23.8 million (13.1%) to $205.5 million for the year ended December 31, 2015, as compared to $181.7 million for the year ended December 31, 2014. The increase was primarily the result of continued drilling activity. On a per unit basis, depletion expense increased $0.96 per Boe or 4.5% to

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$22.40 per Boe for the year ended December 31, 2015 as compared to $21.44 per Boe for the year ended December 31, 2014.

        General and administrative.    General and administrative expenses increased by $7.6 million (29.5%) to $33.4 million for the year ended December 31, 2015, as compared to $25.8 million for the year ended December 31, 2014. Contributing to the change was an increase of $3.2 million related to non-cash compensation expense. Excluding these non-cash items, general and administrative expenses increased $4.4 million (21.0%) to $25.4 million for the year ended December 31, 2015, as compared to $21.0 million for the year ended December 31, 2014. The increase in cash general and administrative expense was primarily attributable to a 12% increase in headcount year-over-year. The remainder of the increase was primarily attributable to increases in professional fees including higher accounting, legal and other fees associated with the Company's financing activities and status as a new public entity. On a per unit basis, cash general and administrative expenses increased from $2.47 per Boe for the year ended December 31, 2014 to $2.77 per Boe for the year ended December 31, 2015.

        Other operating expense.    Other operating expense of $4.2 million for the year ended December 31, 2015 represents stand-by rig costs associated with the charges assessed on early termination of drilling rig contracts. This is a non-recurring charge for which all costs have been recognized as of December 31, 2015.

        Interest expense.    Interest expense increased by $22.5 million (58.0%) to $61.3 million for the year ended December 31, 2015, as compared to $38.8 million for the year ended December 31, 2014. The increase was driven by the issuance of the 2022 Notes and 2023 Notes on April 1, 2014 and February 23, 2015, respectively. During the year ended December 31, 2015, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.39%, 6.75% and 9.25%, respectively. Average outstanding balances for the year ended December 31, 2015 were $144.9 million, $500.0 million and $213.7 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

        Gain (loss) on commodity derivatives.    The gain (loss) on commodity derivatives was a net gain of $158.8 million for the year ended December 31, 2015. The gain was driven by lower average crude oil and natural gas prices ($48.66 per barrel and $2.62 per Mcf, respectively) for the year ended December 31, 2015, as compared to the crude oil and natural gas prices as of December 31, 2014 ($53.45 per barrel and $3.14 per Mcf, respectively) as well as additional hedging activity during 2015.

        Other income (expense).    Other income (expense) for the year ended December 31, 2015 was a net expense of $2.9 million. Financing costs resulted in expenses of $5.5 million primarily driven by amortization of capitalized loan costs, partially offset by the recognition of income associated with the establishment of a $2.0 million valuation allowance associated with the Tax Receivable Agreement (the "TRA") and by the receipt of a $0.7 million distribution of dividend income from our investment in Monarch Natural Gas Holdings, LLC. See Note 11, "Income Taxes—Tax Receivable Agreement," for further details regarding the TRA.

        Income taxes.    The provision for federal and state income taxes for the year ended December 31, 2015 was a benefit of $2.8 million as compared to an expense of $26.2 million for the year ended December 31, 2014. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest.

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Results of Operations—Year ended December 31, 2014 as compared to year ended December 31, 2013

Operating revenues

        Oil and gas sales.    Oil and gas sales increased by $120.3 million (46.6%) to $378.4 million for the year ended December 31, 2014, as compared to $258.1 million for the year ended December 31, 2013. The majority of the increase (67.8%) was due to higher crude oil production volumes with the remainder of the increase being primarily attributable to higher natural gas and natural gas liquid production volumes. Average daily production increased 36.5% to 23,216 Boe per day for the year ended December 31, 2014 as compared to 17,014 Boe per day for the year ended December 31, 2013. Crude oil production increased 59.0% from 1,557 MBbls for the year ended December 31, 2013 to 2,475 MBbls for the year ended December 31, 2014, primarily resulting from the wells acquired from Sabine at the end of 2013, combined with an increase in the number of wells drilled in 2014. Natural gas production increased 24.7% from 17,575 MMcf for the year ended December 31, 2013 to 21,922 MMcf for the year ended December 31, 2014, due to new wells added through drilling and the acquisition of the Sabine wells. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $93.22 per Bbl to $88.93 per Bbl, or 4.6%, year over year. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $3.16 per Mcf to $3.78 per Mcf, or 19.6%, year over year. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $33.30 per Bbl to $32.14 per Bbl, or 3.5%, year over year.

Costs and expenses

        Lease operating.    Lease operating expense increased by $12.7 million (50.6%) to $37.8 million for the year ended December 31, 2014, as compared to $25.1 million for the year ended December 31, 2013. The increase occurred primarily in correlation with the 36.5% increase in production volumes. On a per unit basis, lease operating expense increased by $0.41 per Boe or 10.1%, from $4.05 to $4.46 per Boe, for the year ended December 31, 2014 as compared to the year ended December 31, 2013. On an overall basis, lease operating expense increased due to new wells coming on line and higher compressor and salt water disposal expenses associated with the new wells drilled and acquired from Sabine.

        Production and ad valorem taxes.    Production and ad valorem taxes increased by $7.1 million (45.8%) to $22.6 million for the year ended December 31, 2014, as compared to $15.5 million for the year ended December 31, 2013. Overall production and ad valorem taxes increased in conjunction with the 46.6% increase in revenue. Estimated ad valorem taxes accounted for $3.4 million of the increase from $2.7 million for the year ended December 31, 2013 to $6.1 million for the year ended December 31, 2014, due to new wells coming on line. The average effective rate excluding the impact of ad valorem taxes increased from 5.0% for the year ended December 31, 2013 to 4.4% for the year ended December 31, 2014. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time.

        Exploration.    Exploration expense decreased by $12.6 million from $16.1 million for the year ended December 31, 2013 to $3.5 million for the year ended December 31, 2014. In 2014, costs related to a dry hole as the Company drilled an unsuccessful exploratory well. In 2013, the Company recognized charges for lease abandonment of $14.4 million relating to certain leases, unproved Southridge properties, that the Company did not plan to develop.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization increased by $67.6 million (59.2%) to $181.7 million for the year ended December 31, 2014, as compared to $114.1 million for the year ended December 31, 2013. The increase was primarily the result of continued drilling activity and the acquisition of the Sabine wells at the end of 2013. On a per unit

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basis, depletion expense increased $3.06 per Boe or 16.6% to $21.44 per Boe for the year ended December 31, 2014 as compared to $18.38 per Boe for the year ended December 31, 2013. The per unit increase resulted from the higher cost to drill wells in 2014 compared to historical wells.

        General and administrative.    General and administrative expenses decreased by $6.1 million (19.1%) to $25.8 million for the year ended December 31, 2014, as compared to $31.9 million for the year ended December 31, 2013. A decrease of $6.8 million related to stock compensation expense (of which $9.6 million related to the immediate vesting of certain shares on the IPO date in 2013, offset by $2.0 million of expense related to new incentive awards in 2014) and $2.4 million related to a one-time non-cash distribution in 2013 to management related to the Monarch incentive plan. Excluding these non-cash items, general and administrative expenses increased $2.7 million (14.7%) to $21.0 million for the year ended December 31, 2014, as compared to $18.3 million for the year ended December 31, 2013. The increase in cash general and administrative expense is attributable to an increase in personnel costs and office expense due to an increase in headcount to support our increased drilling activity. On a per unit basis, cash general and administrative expenses decreased from $2.95 per Boe for the year ended December 31, 2013 to $2.47 per Boe for the year ended December 31, 2014. The increase in activity resulting from drilling and the acquisition of the Sabine properties significantly increased production (36.5% on a Boe basis) but did not result in a proportional increase in general and administrative expenses.

        Interest expense.    Interest expense increased by $11.4 million (41.6%) to $38.8 million for the year ended December 31, 2014, as compared to $27.4 million for the year ended December 31, 2013. The increase was driven by the issuance of the 2022 Notes on April 1, 2014. During the year ended December 31, 2014, borrowings under the Revolver, the second lien term loan and the 2022 Notes bore interest at a weighted average rate of 2.51%, 9.13% and 6.75%, respectively. Average outstanding balances for the year ended December 31, 2014 were $333.8 million, $39.5 million and $376.7 million under the Revolver, the second lien term loan and the 2022 Notes, respectively.

        Gain (loss) on commodity derivatives.    The gain (loss) on commodity derivatives was a net gain of $189.6 million for the year ended December 31, 2014. The gain was driven by lower average crude oil prices ($93.17 per barrel) for the year ended December 31, 2014, as compared to the crude oil prices as of December 31, 2013 ($98.17 per barrel). This was partially offset by higher average natural gas prices ($4.37 per Mcf) for the year ended December 31, 2014, as compared to the natural gas price as of December 31, 2013 ($4.31 per Mcf).

        Other income (expense).    Other income (expense) was a loss of $7.6 million for the year ended December 31, 2014, compared to a loss of $3.4 million for the year ended December 31, 2013. The increase of $4.2 million (123.5%) was driven by increased financing costs.

        Income taxes.    The provision for income taxes reflects our reorganization and recapitalization which occurred in connection with the Company's initial public offering. Following the IPO in July 2013, the Company is subject to federal and state income and franchise taxes, while only the Texas franchise tax applied to JEH prior to the IPO. Income tax expense was an expense of $26.2 million for the year ended December 31, 2014 compared to a benefit of $0.1 million for the year ended December 31, 2013. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest.

Liquidity and Capital Resources

        Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we

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pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined below), facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at December 31, 2015 reflects a positive working capital balance largely due to the value of our current commodity derivative assets as of year-end. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolver to help manage our working capital.

        Availability under the Revolver is subject to a borrowing base. Our borrowing base at December 31, 2015 was $510 million of which $110 million was utilized leaving an unused capacity of $400 million. The borrowing base will be redetermined at least semi-annually on or about April 1 and October 1 of each year, with such redetermination based primarily on reserve reports using lender commodity price expectations at such time. In light of current commodity prices, it is our expectation that the borrowing base will be reduced during the upcoming redetermination. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

        The Revolver also contains a covenant which restricts the ability of Jones Energy, Inc. to (i) hold any assets, (ii) incur, create, assume, or suffer to exist any debt or any other liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any other activity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of operational costs and expenses).

        Jones Energy, Inc. and its consolidated subsidiaries are also required under the Revolver to maintain the following financial ratios:

•

a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and

•

a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

        As of December 31, 2015, our total leverage ratio is approximately 3.2 and our current ratio is approximately 6.9, as calculated based on the requirements in our covenants. We believe that we are in compliance with all terms of our Revolver and expect to maintain compliance during 2016. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2016 and beyond. In the event it were to became necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as hedge restructuring. While it is our expectation that we will continue to be in compliance with our covenants, no assurance can be given that this will be the case. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

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        As we do not plan on resuming drilling activities until well costs create acceptable rates of return at strip prices, our 2016 capital budget will be primarily focused on workovers of existing wells and field optimization activities. The amount of capital we expend may fluctuate materially based on the market conditions for commodity prices and costs of drilling and completing wells, the economic returns being realized and the success of our drilling results as the year progresses. We expect to fund our entire 2016 capital budget with cash flows from operations and borrowings under our Revolver. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuance of debt and/or equity securities.

        The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. For example, due to the steep reduction of commodity prices experienced in the fourth quarter of 2014, we reduced our capital budget for 2015 to $210 million and have further reduced our capital budget to $25 million in 2016. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continuously monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

        The following table summarizes our cash flows for the years ended December 31, 2015, 2014 and 2013:

	Year Ended December 31,
(in thousands of dollars)	2015			2014			2013
Net cash provided by operating activities	$	69,030		$	265,423		$	148,573
Net cash used in investing activities		(168,401	)		(463,903	)		(368,277	)
Net cash provided by financing activities		107,698			188,226			219,798
Net increase (decrease) in cash	$	8,327		$	(10,254	)	$	94

Cash Flow Provided by Operating Activities

        Net cash provided by operating activities was $69.0 million for the year ended December 31, 2015 as compared to cash provided by operating activities of $265.4 million for the year ended December 31, 2014. The decrease in operating cash flows was primarily due to a $183.8 million decrease in oil and gas revenues for the year ended December 31, 2015 as compared to the year ended December 31, 2014. The decrease in revenue was attributable to the decline in commodity prices.

        Net cash provided by operating activities was $265.4 million for the year ended December 31, 2014 as compared to cash provided by operating activities of $148.6 million for the year ended December 31, 2013. The increase in operating cash flows was primarily due to a $120.3 million increase in oil and gas revenues for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in revenue was primarily driven by a 59.0% increase in oil production volumes as a result of drilling and the acquisition of the Sabine wells in the fourth quarter of 2013, combined with increases in natural gas and NGL production volumes.

        Our operating cash flows are sensitive to a number of variables, the most significant of which is oil, NGL, and natural gas prices. For additional information on the impact of changing prices on our financial position, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

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Cash Flow Used in Investing Activities

        Net cash used in investing activities was $168.4 million for the year ended December 31, 2015 as compared to cash used in investing activities of $463.9 million for the year ended December 31, 2014. The decrease was primarily driven by the reduction in capital expenditures which decreased $163.3 million during the year ended December 31, 2015 as compared to the year ended December 31, 2014 due to a decrease in drilling activity. Additionally, cash flows from current period settlements of our commodity derivative instruments resulted in net cash receipts of $144.1 million for the year ended December 31, 2014 as compared to net payments of $3.7 million for the year ended December 31, 2014 as a result of lower commodity prices.

        Net cash used in investing activities was $463.9 million for the year ended December 31, 2014 as compared to cash used in investing activities of $368.3 million for the year ended December 31, 2013. The increase was primarily driven by higher capital expenditures which increased $277.0 million during the year ended December 31, 2014 as compared to the year ended December 31, 2013 due to an increase in drilling activity. The increase in capital expenditures was partially offset by the absence of acquisitions of property during 2014 as compared to the $178.2 million acquisition of the Sabine properties at the end of 2013. $15.7 million was refunded in 2014 after determining the final purchase price of the Sabine properties that were acquired in 2013. Additionally, cash flows from current period settlements of our commodity derivative instruments were net payments of $3.7 million for the year ended December 31, 2014 as compared to net receipts of $7.6 million for the year ended December 31, 2013 as a result of higher commodity prices that occurred early in the year 2014.

        We expect our 2016 capital expenditures to be approximately $25.0 million, which is an 87.5% decrease from the $200.1 million incurred for 2015 excluding the impact of asset retirement costs. Expenditures for development and exploration of oil and gas properties are the primary use of our capital resources. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, the degree of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Cash Flow Provided by Financing Activities

        Net cash provided by financing activities was $107.7 million for the year ended December 31, 2015 as compared to net cash provided by financing activities of $188.2 million for the year ended December 31, 2014. The decrease in cash flows provided by financing activities was primarily due to a $263.5 million reduction in proceeds from the issuance of senior notes. During 2015, we made net payment on our credit facility of $251.6 million as compared to net payments of $311.4 million during 2014.

        Net cash provided by financing activities was $188.2 million for the year ended December 31, 2014 as compared to net cash provided by financing activities of $219.8 million for the year ended December 31, 2013. The decrease in cash flows provided by financing activities was primarily due to net payment on our credit facility of $311.4 million during 2014 as compared to net borrowing of $47.3 million during 2013. The net proceeds from the issuance of our senior notes of $490.0 million (net of expenses) in the second quarter of 2014 were used to repay borrowings under the credit facilities of $468 million during the year ended December 31, 2014.

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Senior Notes due 2022

        On April 1, 2014, JEH and Jones Energy Finance Corp., JEH's wholly-owned subsidiary formed for the sole purpose of co-issuing certain of JEH's debt (together the "Issuers"), sold $500.0 million in aggregate principal amount of the Issuers' 6.75% senior notes due 2022 (the "2022 Notes"). The Company used the net proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding borrowings under the Revolver ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014.

        The 2022 Notes are guaranteed on a senior unsecured basis by us and by all of our existing significant subsidiaries. The 2022 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

        We may redeem the 2022 Notes at any time on or after April 1, 2017 at a declining redemption price set forth in the indenture, plus accrued and unpaid interest.

        The indenture governing the 2022 Notes contains covenants that, among other things, limit our ability to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us, consolidate, merge or transfer all of our assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the 2022 Notes are rated investment grade by Standard & Poor's or Moody's.

Senior Notes due 2023

        On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the "2023 Notes") in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015.

        The 2023 Notes are guaranteed on a senior unsecured basis by us and by all of our existing significant subsidiaries. The 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

        We may redeem the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the indenture, plus accrued and unpaid interest.

        The indenture governing the 2023 Notes contains covenants that, among other things, limit our ability to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us, consolidate, merge or transfer all of our assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the 2023 Notes are rated as investment grade by Standard & Poor's or Moody's.

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Credit Facilities

        Senior Secured Revolving Credit Facility.    JEH has a $1 billion senior secured revolving credit facility (the "Revolver") with Wells Fargo Bank, N.A. as the administrative agent, and a syndicate of lenders. Availability under the Revolver is subject to a borrowing base, which is currently $510 million. The Revolver matures in November 2019. As of December 31, 2015, JEH had borrowings of $110 million outstanding under the Revolver. JEH's obligations under the Revolver are guaranteed by us and JEH's subsidiaries and are secured by substantially all of their assets (other than equity interests of JEH held by us).

        On November 6, 2014, JEH entered into a ninth amendment (the "Ninth Amendment") to the Revolver. The Ninth Amendment amended the Revolver to, among other things, (1) increase the borrowing base under the Revolver from $550 million to $625 million, and (2) extend the maturity date of the Revolver to November 6, 2019. The foregoing description of the Ninth Amendment is not complete and is qualified by reference to the complete document, which is filed as Exhibit 10.22 to this Annual Report and is incorporated herein by reference.

        The borrowing base under our Revolver will be redetermined at least semi- annually on or about April 1 and October 1 of each year. JEH and the administrative agent (acting at the direction of lenders holding at least 66²/3% of the outstanding loans) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our material operating agreements or upon the cancellation or termination of certain of our joint development agreements. The borrowing base may also be reduced as a result of our issuance of unsecured notes, our termination of material hedging positions or our consummation of significant asset sales.

        If the aggregate outstanding principal amount of the revolving loans under the Revolver exceeds the borrowing base as a result of a scheduled or interim adjustment of the borrowing base, we must prepay revolving loans in an amount equal to such excess within 90 days following the date the adjustment occurs or the date we receive notice thereof (with at least one-half of the prepayment to be paid or deposited within 45 days following such date). However, if such a borrowing base deficiency results from a permitted disposition of oil and gas properties or from terminations or modifications of hedge positions, we must immediately make such prepayment and/or deposit of cash collateral. Otherwise, all unpaid principal and interest is due at maturity.

        Interest on loans under our Revolver is calculated, at JEH's option, at either (i) the LIBO Rate for the applicable interest period plus a margin ranging from 1.50% to 2.50% based on the level of borrowing base utilization at such time or (ii) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, (y) the federal funds rate plus 0.50% and (z) the one-month adjusted LIBO Rate plus 1.00%, plus a margin ranging from 0.50% to 1.50% based on the level of borrowing base utilization at such time. JEH is also required to pay a quarterly commitment fee on the unused portion of the aggregate commitments of the lenders, at a rate per annum of either 0.375% or 0.50%, depending on our utilization of the borrowing base.

        The Revolver contains various covenants that, among other things, limit our ability to:

•

incur indebtedness;

•

grant liens on our assets;

•

pay dividends or distributions or redeem any of our equity interests;

•

make certain investments, loans and advances;

•

merge into or with or consolidate with any other person, or dispose of all or substantially all of our property to any other person;

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•

engage in certain asset dispositions;

•

enter into transactions with affiliates;

•

grant negative pledges or agree to restrict dividends or distributions from subsidiaries;

•

allow gas imbalances, take-or-pay or certain other prepayments with respect to oil and gas properties; and

•

enter into certain derivative arrangements.

The Revolver also contains a covenant which restricts the ability of Jones Energy, Inc. to (i) hold any assets, (ii) incur, create, assume, or suffer to exist any debt or any other liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any other activity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of operational costs and expenses).

        Jones Energy, Inc. and its consolidated subsidiaries are also required under the Revolver to maintain the following financial ratios:

•

a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and

•

a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

        We believe that we are in compliance with the terms of our Revolver. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

        Second Lien Term Loan Facility.    Prior to the issuance of the 2022 Notes JEH had a $160 million second lien term loan facility (the "Term Loan") with Wells Fargo Energy Capital, Inc., as the administrative agent, and a syndicate of lenders. All outstanding borrowings on the Term Loan were repaid using a portion of the proceeds obtained from issuing the 2022 Notes in the second quarter 2014. The Company subsequently terminated the Term Loan in accordance with its terms.

Off-Balance Sheet Arrangements

        At December 31, 2015, we did not have any off-balance sheet arrangements.

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Contractual Obligations

        The following table summarizes our contractual obligations as of December 31, 2015:

	Payments Due by Period
(dollars in thousands of dollars)	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		Thereafter
Long-term debt obligations	$	860,000	$	—	$	110,000	$	—	$	750,000
Interest expense(1)		386,273		59,504		178,116		113,750		34,903
Commodity derivative obligations		11		11		—		—		—
Operating lease obligations		4,583		945		3,261		377		—
Total	$	1,250,867	$	60,460	$	291,377	$	114,127	$	784,903

(1)

Interest expense is estimated based on the outstanding balance at December 31, 2015 multiplied by the weighted average interest rate during 2015.

Excluded from the table above, are the following:

        We recognize as a liability an asset retirement obligation, or ARO, associated with the retirement of a tangible long-lived asset in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration.

        The holders of JEH Units, including Jones Energy, Inc., incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro rata cash tax distributions to its unitholders (including us) based on income allocated to such unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on the estimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate of federal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefit of the deduction for any state taxes. Based on our 2016 budget and debt extinguishment through February 29, 2016, we estimate that the amount of tax distributions to JEH unitholders (other than us), plus the amount of our cash tax liabilities, in 2016 would be approximately $38.3 million based on information available as of this filing. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors.

        The Company entered into the Tax Receivable Agreement with JEH and the pre-IPO owners that provides for payment by Jones Energy, Inc. to exchanging pre-IPO owners of 85% of the benefits, if any, that Jones Energy, Inc. is deemed to realize as a result of any exchange. As a result of exchanges made prior to December 31, 2015, the Company recorded a TRA liability of $38.1 million. Estimating the timing of payments made under the Tax Receivable Agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors.

        In the event we are allocated taxable income relating to 2016 from JEH, we are likely to make a payment of a portion of the TRA liability during 2017. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook," and see "Risk Factors—We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may receive (or be deemed to receive), and the amounts of such payments could be significant." for further discussion of these items.

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Critical Accounting Policies and Estimates

        The discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. As used herein, the following acronyms have the following meanings: "FASB" means the Financial Accounting Standards Board; the "Codification" refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; "ASC" means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and "ASU" means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB.

        The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies.

        Use of Estimates.    The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the amounts of revenues and expenses reported for the period then ended.

        Reserves.    Reserve estimates significantly impact depreciation and depletion expense and the calculation of potential impairments of oil and gas properties. Under the SEC rules, proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

        Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

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        Reserves were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month within the twelve-month period ending on the date as of which the applicable estimate is presented. These prices were adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

        Periodic revisions to the estimated reserves and related future cash flows may be necessary as a result of a number of factors, including changes in oil and natural gas prices, reservoir performance, new drilling and completion, purchases, sales and terminations of leases, drilling and operating cost changes, technological advances, new geological or geophysical data or other economic factors. All of these factors are inherently estimates and are inter-dependent. While each variable carries its own degree of uncertainty, some factors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, as such revisions could be negatively impacted by:

•

Declines in commodity prices or actual realized prices below those assumed for future years;

•

Increases in service costs;

•

Increases in future global or regional production or decreases in demand;

•

Increases in operating costs;

•

Reductions in availability of drilling, completion, or other equipment.

        If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material.

        Property and Equipment.    Oil and gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

        Impairment—The capitalized costs of proved oil and gas properties are reviewed at least annually for impairment, whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows from a producing field to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production and future oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the field assets is reduced to fair value. For our proved oil and gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

        Unproved leasehold costs are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the statement of operations.

        Sales—Sales of significant portions of a proved field are charged to income as incurred. Gain or loss on the sale is recognized to the extent of the difference between the net proceeds received and the remaining carrying value of the properties sold. Proceeds from the sale of insignificant portions of a larger proved field are accounted for as a recovery of costs, thereby reducing the carrying value of the

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field until such value reaches zero. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

        Derivative Financial Instruments.    We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and NGLs. We record such derivative instruments as assets or liabilities in the balance sheet (see Note 7, "Fair Value Measurement," in the Notes to Consolidated Financial Statements for further information on fair value). Estimating the fair value of derivative financial instruments requires management to make estimates and judgments regarding volatility and counterparty credit risk. We use net presentation of derivative assets and liabilities when such assets and liabilities are with the same counterparty and allowed under the ISDA trading agreement with such counterparty.

        We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in net income in the period of the change as "Net gain (loss) on commodity derivatives."

        Share-Based Compensation.    We measure and record compensation expense for all share-based payment awards to employees and directors based on estimated grant-date fair values. Compensation costs for share-based awards are recognized over the requisite service period based on the grant-date fair value. Prior to our IPO, we were not publicly traded, and did not have a listed price with which to calculate fair value. We have historically and consistently calculated fair value using combined valuation models including an enterprise valuation approach; an income approach, utilizing future discounted and undiscounted cash flows; and a market approach, taking into consideration peer group analysis of publicly traded companies, and when available, actual cash transactions in our common stock.

        Acquisitions.    Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in our statement of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities, if any, based on their estimated fair value at the time of the acquisition. We have historically and consistently calculated fair value using combined valuation models including an enterprise valuation approach; an income approach, utilizing future discounted and undiscounted cash flows; and a market approach, taking into consideration peer group analysis of publicly traded companies.

        Asset Retirement Obligations.    We recognize as a liability an asset retirement obligation, or ARO, associated with the retirement of a tangible long-lived asset in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. We measure the fair value of the ARO using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

        Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

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Liability under Tax Receivable Agreement

        In connection with the IPO, the Company entered into a Tax Receivable Agreement (the "TRA") which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company's Class B common stock held by those owners for shares of the Company's Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings.

        As a result of exchanges made, the Company accrues the estimated future tax benefits and accounts for this estimated amount as a reduction of deferred tax liabilities on its consolidated balance sheet. The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company's payments under the TRA constituting imputed interest. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

Recent Accounting Pronouncements

        See Note 2, "Significant Accounting Policies—Recent Accounting Pronouncements" in our Notes to the Consolidated Financial Statements.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk

        We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

        We do not designate these or future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Commodity price risk and hedges

        Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at December 31, 2015 was a net asset of $217.5 million.

        As of December 31, 2015, we have hedged approximately 55% of our total forecasted production from proved reserves through December 31, 2017. For information regarding the terms of these hedges, please see "—Basis of presentation—Hedging" above. The production hedged thereby is consistent with the assumed drilling schedule and monthly production levels in the December 31, 2015 reserve report prepared by Cawley Gillespie, which is based on prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in this reserve report, perhaps materially. Please read "Risk factors—Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves."

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Counterparty and customer credit risk

        Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of these significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

        While we do not typically require our partners, customers and counterparties to post collateral, we have begun to make cash calls to our partners for their share of future project expenditures. We periodically review, evaluate and assess the credit standing of our partners or customers for oil and gas receivables and the counterparties on our derivative instruments. This evaluation may include reviewing a party's credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, and undertaking the due diligence necessary to determine creditworthiness. The counterparties on our derivative instruments currently in place are lenders under the revolving credit facility with investment grade ratings. We are not permitted under the terms of the revolving credit facility to enter into derivative instruments with counterparties outside of the banks who are lenders under the revolving credit facility. As a result, any future derivative instruments will be with these or other lenders under the revolving credit facility who will also likely carry investment grade ratings.

Interest rate risk

        We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of the senior secured revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The base rate margins under the terminated term loan were 6.0-7.0% depending on the base rate used and the amount of the loan outstanding. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the year ended December 31, 2015, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.39%, 6.75% and 9.25%, respectively.

Item 8.    Financial Statements and Supplementary Data

        Our consolidated financial statements and supplementary financial data are included in this Annual Report beginning on page F-1.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the

85

Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

        Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2015 because our material weakness, identified at the time of our IPO, has not been fully remediated throughout the year ended December 31, 2015.

Management's Assessment of Internal Control over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Prior to the completion of our initial public offering, we were a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. In previous years, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review of our financial statements and supervision by appropriate individuals. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. We concluded that these control deficiencies, although varying in severity, constitute a material weakness in our control environment.

        As of December 31, 2015, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control—Integrated Framework (2013). Based on this assessment, management determined that, as of December 31, 2015, a material weakness related to design and execution of our controls continued to exist. Additionally, this material weakness could result in a misstatement of account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Because of this material weakness, management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

        A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Attestation Report of the Registered Public Accounting Firm

        Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of

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the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an "emerging growth company" as defined in the JOBS Act.

Remediation steps to address the material weakness

        The material weakness in our internal control over financial reporting was previously disclosed in Item 9A, Controls and Procedures of our Annual Report on Form 10-K for the years ended December 31, 2013 and December 31, 2014.

        Management took steps during the years ended December 31, 2014 and 2015 to address the previously identified material weakness, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company. We have strengthened our internal control environment through the addition of skilled accounting personnel. This team has enabled us to expedite our month-end close process, thereby facilitating the timely preparation of financial reports. We continue to hire incremental qualified staff, as needed, in conjunction with a comprehensive review of our internal controls and formalization of our review and approval processes.

        The design and implementation of new accounting processes and control procedures, in conjunction with the staffing improvements, made progress toward remediation of the previously noted material weakness.

        Shortly after the initial public offering, the Company engaged an independent accounting and consulting firm to fulfill its internal audit needs. The principal focus of the internal audit function has been to test the design and operating effectiveness of our controls. Based upon our testing and evaluation of the effectiveness of our internal controls, we have concluded we have designed but not fully implemented new processes and controls to remediate the material weakness identified as of December 31, 2015.

Changes in Internal Control over Financial Reporting

        As described above under Remediation Steps to address the material weakness, there were changes in our internal control over financial reporting, relating to the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

        None.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance

        The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 11.    Executive Compensation

        The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

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Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

        The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 14.    Principal Accounting Fees and Services

        The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a)

The following documents are filed as part of this report or incorporated by reference:

        (1)    Financial Statements.    Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying footnotes, see "Index to Consolidated Financial Statements" on page F-1 of this Annual Report.

        (2)    Financial Statement Schedules.    All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

        (3)    Exhibits.    The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K.

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EXHIBIT INDEX

Exhibit No.		Description
	2.1	Purchase and Sale Agreement by and between Chalker Energy Partners II, LLC, the listed participating owners and Jones Energy Holdings, LLC, dated November 28, 2012 (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on June 7, 2013).
	2.2	Purchase and Sale Agreement by and between Sabine Mid-Continent LLC, as seller, and Jones Energy Holdings, LLC, as purchaser, dated as of November 22, 2013 (incorporated by reference to Exhibit 2.2 to the Company's Annual Report on Form 10-K filed on March 14, 2014).
	3.1	Amended and Restated Certificate of Incorporation of Jones Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	3.2	Amended and Restated Bylaws of Jones Energy, Inc. (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	4.1	Form of Class A common stock Certificate (incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on June 7, 2013).
	4.2	Registration Rights and Stockholders Agreement, dated as of July 29, 2013 (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	4.3	Indenture, dated April 1, 2014, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on April 1, 2014).
	4.4	Registration Rights Agreement, dated April 1, 2014, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and Citigroup Global Markets Inc., as the sole representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on April 1, 2014).
	4.5	Indenture, dated February 23, 2015, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Jones Energy, Inc.'s Current Report on Form 8-K filed on February 27, 2015).
	4.6	Registration Rights Agreement dated February 23, 2015, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and the purchasers named therein (incorporated by reference to Exhibit 4.2 to Jones Energy, Inc.'s Current Report on Form 8-K filed on February 27, 2015).
	10.1	Third Amended and Restated Limited Liability Company Agreement of Jones Energy Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	10.2	Exchange Agreement, dated as of July 29, 2013, by and among Jones Energy, Inc., Jones Energy Holdings, LLC and the members of Jones Energy Holdings, LLC party thereto (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on July 30, 2013).

89

Exhibit No.			Description
	10.3		Tax Receivable Agreement, dated as of July 29, 2013, by and among Jones Energy, Inc., Jones Energy Holdings, LLC and the members of Jones Energy Holdings, LLC party thereto (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	10.4	†	Jones Energy, Inc. 2014 Omnibus Incentive Plan, effective as of July 29, 2013 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	10.5	†	Jones Energy, Inc. Short Term Incentive Plan, effective as of July 29, 2013 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed on July 30, 2013).
	10.6	†	Form of Director Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 4, 2013).
	10.7	†	Form of Employee Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on May 27, 2014).
	10.8	†	Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on May 27, 2014).
	10.9	†	Jones Energy, LLC Executive Deferral Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on October 23, 2013).
	10.10	†	Jones Energy Holdings, LLC Monarch Equity Plan (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.11		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on June 7, 2013).
	10.12		Credit Agreement, dated as of December 31, 2009, among Jones Energy Holdings, LLC, as borrower, Wells Fargo Bank N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.13		Agreement and Amendment No. 1 to Credit Agreement (First Lien) (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.14		Master Assignment, Agreement and Amendment No. 2 to Credit Agreement (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.15		Master Assignment, Agreement and Amendment No. 3 to Credit Agreement (incorporated by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.16		Agreement and Amendment No. 4 to Credit Agreement (First Lien) (incorporated by reference to Exhibit 10.13 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.17		Master Assignment, Agreement and Amendment No. 5 to Credit Agreement (incorporated by reference to Exhibit 10.14 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).

90

Exhibit No.			Description
	10.18		Waiver and Amendment No. 6 to Credit Agreement (incorporated by reference to Exhibit 10.15 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.19		Waiver, Agreement and Amendment No. 7 to Credit Agreement and Amendment to Guarantee and Collateral Agreement (incorporated by reference to Exhibit 10.24 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on June 17, 2013).
	10.20		Borrowing Base Increase Agreement, dated as of December 18, 2013, among Jones Energy Holdings, LLC, as borrower, certain subsidiaries of Jones Energy Holdings, LLC, as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K filed on March 14, 2014).
	10.21		Agreement and Amendment No. 8 to Credit Agreement dated as of January 29, 2014, among Jones Energy Holdings, LLC, as borrower, Jones Energy, Inc., Jones Energy, LLC and Nosley Assets, LLC, as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K filed on March 14, 2014).
	10.22	*	Master Assignment, Agreement and Amendment No. 9 to Credit Agreement dated as of November 6, 2014, among Jones Energy Holdings, LLC, as borrower, Jones Energy, Inc., Jones Energy, LLC and Nosley Assets, LLC, as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
	10.23		Guarantee and Collateral Agreement, dated as of January 29, 2014, between Jones Energy, Inc., as guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K filed on March 14, 2014).
	10.24		Second Lien Credit Agreement, dated as of December 31, 2009, among Jones Energy Holdings, LLC, as borrower, Wells Fargo Energy Capital, Inc., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.16 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.25		Agreement and Amendment No. 1 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.17 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.26		Agreement and Amendment No. 2 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.18 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.27		Agreement and Amendment No. 3 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.19 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.28		Agreement and Amendment No. 4 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.29		Agreement and Amendment No. 5 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.21 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).

91

Exhibit No.			Description
	10.30		Waiver and Amendment No. 6 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.22 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
	10.31		Waiver, Agreement and Amendment No. 7 to Second Lien Credit Agreement (incorporated by reference to Exhibit 10.25 to the Company's Registration Statement on Form S-1, File No. 333-188896, filed on June 17, 2013).
	10.32		Firm Crude Oil Gathering and Transportation Agreement, dated September 26, 2014, by and between Monarch Oil Pipeline, LLC and Jones Energy, LLC (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014).
	10.33		Gathering and Transportation Services Agreement, dated as of September 26, 2014, by and between Monarch Oil Pipeline, LLC and Jones Energy, LLC (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014).
	10.34	*	Amended and Restated Firm Crude Oil Gathering and Transportation Agreement, dated October 23, 2015, by and between Monarch Oil Pipeline, LLC and Jones Energy, LLC.
	10.35	*	Amended and Restated Gathering and Transportation Services Agreement, dated as of October 23, 2015, by and between Monarch Oil Pipeline, LLC and Jones Energy, LLC.
	21.1	*	List of Subsidiaries of Jones Energy, Inc.
	23.1	*	Consent of PricewaterhouseCoopers LLP.
	23.2	*	Consent of Cawley Gillespie & Associates, Inc.
	31.1	*	Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).
	31.2	*	Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).
	32.1	*	Section 1350 Certification of Jonny Jones (Principal Executive Officer).
	32.2	*	Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
	99.1	*	Summary Report of Cawley, Gillespie & Associates, Inc. for reserves as of December 31, 2015
	101.INS	*	XBRL Instance Document.
	101.SCH	*	XBRL Taxonomy Extension Schema Document.
	101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document.
	101.DEF	*	XBRL Taxonomy Extension Definition Linkbase Document.
	101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document.
	101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document.

*—filed herewith

†—Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).

92

SIGNATURES

        Pursuant to the requirements of Section 13 or 14(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	JONES ENERGY, INC. (registrant)
Date: March 9, 2016	By:	/s/ JONNY JONES
		Name:	Jonny Jones
		Title:	Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ JONNY JONES Jonny Jones	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	March 9, 2016
/s/ MIKE S. MCCONNELL Mike S. McConnell	Director and President	March 9, 2016
/s/ ROBERT J. BROOKS Robert J. Brooks	Executive Vice President and Chief Financial Officer (Principal Accounting and Financial Officer)	March 9, 2016
/s/ HOWARD I. HOFFEN Howard I. Hoffen	Director	March 9, 2016
/s/ GREGORY D. MYERS Gregory D. Myers	Director	March 9, 2016
/s/ HALBERT S. WASHBURN Halbert S. Washburn	Director	March 9, 2016
/s/ ALAN D. BELL Alan D. Bell	Director	March 9, 2016
/s/ ROBB L. VOYLES Robb L. Voyles	Director	March 9, 2016

93

GLOSSARY OF OIL AND NATURAL GAS TERMS

        The terms and abbreviations defined in this section are used throughout this Annual Report on Form 10K:

        "AMI"—Area of mutual interest, typically referring to a contractually defined area under a joint development agreement whereby parties are subject to mutual participatory rights and restrictions.

        "Basin"—A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

        "Bbl"—One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

        "Boe"—Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

        "Boe/d"—Barrels of oil equivalent per day.

        "British thermal unit (BTU)"—The heat required to raise the temperature of one pound of water by one degree Fahrenheit.

        "Completion"—The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

        "Condensate"—A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        "Developed acreage"—The number of acres that are allocated or assignable to productive wells or wells capable of production.

        "Developed reserves"—Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

        "Development well"—A well drilled within the proved area of a oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

        "Dry hole"—A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion of the well, such that proceeds from the sale of such production do not exceed production expenses and taxes.

        "Economically producible"—A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

        "Exploratory well"—A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil.

        "Farm-in or farm-out"—An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interests received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."

94

        "Field"—An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition.

        "Formation"—A layer of rock which has distinct characteristics that differ from nearby rock.

        "Fracture stimulation"—A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

        "Gross acres or gross wells"—The total acres or well, as the case may be, in which a working interest is owned.

        "Horizontal drilling"—A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

        "Joint development agreement"—Includes joint venture agreements, farm-in and farm-out agreements, joint operating agreements and similar partnering arrangements.

        "MBbl"—One thousand barrels of oil, condensate or NGLs.

        "MBoe"—One thousand barrels of oil equivalent, determined using the equivalent of six Mcf of natural gas to one Bbl of crude oil.

        "Mcf"—One thousand cubic feet of natural gas.

        "MMBoe"—One million barrels of oil equivalent.

        "MMBtu"—One million British thermal units.

        "MMcf"—One million cubic feet of natural gas.

        "Net acres or net wells"—The sum of the fractional working interest owned in gross acres or gross wells. An owner who has 50% interest in 100 acres owns 50 net acres.

        "Net revenue interest"—An owner's interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

        "Possible reserves"—Additional reserves that are less certain to be recognized than probable reserves.

        "Probable reserves"—Additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.

        "Productive well"—A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

        "Prospect"—A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.

        "Proved developed non-producing"—Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved but non-producing reserves.

        "Proved developed reserves"—Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

        "Proved reserves"—Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data to be economically producible.

95

        "Proved undeveloped reserves (PUD)"—Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

        "Recompletion"—The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

        "Reserves"—Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

        "Reservoir"—A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        "Royalty interest"—An interest in an oil and natural gas property entitling the owner to a share of oil or gas production free of production costs.

        "Spacing"—The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

        "Spud"—The commencement of drilling operations of a new well.

        "Standardized measure of discounted future net cash flows"—The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the regulations of the Securities and Exchange Commission, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.

        "Trend"—A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

        "Unconventional formation"—A term used in the oil and natural gas industry to refer to a formation in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, or (3) oil and gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to produce economic flow rates

        "Undeveloped acreage"—Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

        "Wellbore"—The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

        "Working interest"—The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals and receive a share of the production. The working interest owners bear the exploration, development, and operating costs of the property.

96

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Financial Statements
Balance Sheets	F-3
Statements of Operations	F-4
Statement of Changes in Stockholders' / Members' Equity	F-5
Statements of Cash Flows	F-6
Notes to the Consolidated Financial Statements	F-7
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	F-47
Supplemental Quarterly Financial Information (Unaudited)	F-51

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Jones Energy, Inc.:

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders' / members' equity, and cash flows present fairly, in all material respects, the financial position of Jones Energy, Inc. and its subsidiaries at December 31, 2015 and 2014 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 9, 2016

F-2

Jones Energy, Inc.

Consolidated Balance Sheets

December 31, 2015 and 2014

(in thousands of dollars)	December 31, 2015			December 31, 2014
Assets
Current assets
Cash	$	21,893		$	13,566
Restricted cash		330			149
Accounts receivable, net
Oil and gas sales		19,292			51,482
Joint interest owners		11,314			41,761
Other		15,170			12,512
Commodity derivative assets		124,207			121,519
Other current assets		2,298			3,374
Total current assets		194,504			244,363
Oil and gas properties, net, at cost under the successful efforts method		1,635,766			1,638,860
Other property, plant and equipment, net		3,873			4,048
Commodity derivative assets		93,302			87,055
Other assets		17,967			20,352
Deferred tax assets		—			171
Total assets	$	1,945,412		$	1,994,849
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	7,467		$	136,337
Oil and gas sales payable		32,408			70,469
Accrued liabilities		27,341			19,401
Commodity derivative liabilities		11			—
Asset retirement obligations		679			3,074
Total current liabilities		67,906			229,281
Long-term debt		847,912			860,000
Deferred revenue		11,417			13,377
Commodity derivative liabilities		—			28
Asset retirement obligations		20,301			10,536
Liability under tax receivable agreement		38,052			803
Deferred tax liabilities		22,972			27,474
Total liabilities		1,008,560			1,141,499
Commitments and contingencies (Note 14)
Stockholders' equity
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding at December 31, 2015 and 12,672,260 shares issued and 12,649,658 shares outstanding at December 31, 2014		31			13
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding at December 31, 2015 and 36,719,499 shares issued and outstanding at December 31, 2014		31			37
Treasury stock, at cost; 22,602 shares at December 31, 2015 and December 31, 2014		(358	)		(358	)
Additional paid-in-capital		363,723			178,763
Retained earnings (deficit)		36,569			38,950
Stockholders' equity		399,996			217,405
Non-controlling interest		536,856			635,945
Total stockholders' equity		936,852			853,350
Total liabilities and stockholders' equity	$	1,945,412		$	1,994,849

The accompanying notes are an integral part of these consolidated financial statements.

F-3

Jones Energy, Inc.

Consolidated Statements of Operations

Years Ended December 31, 2015, 2014 and 2013

	Year Ended December 31,
(in thousands except per share data)	2015			2014			2013
Operating revenues
Oil and gas sales	$	194,555		$	378,401		$	258,063
Other revenues		2,844			2,196			1,106
Total operating revenues		197,399			380,597			259,169
Operating costs and expenses
Lease operating		41,027			37,760			25,129
Production taxes		12,130			22,556			15,517
Exploration		6,551			3,453			16,125
Depletion, depreciation and amortization		205,498			181,669			114,136
Accretion of ARO liability		1,087			770			608
General and administrative		33,388			25,763			31,902
Other operating		4,188			—			—
Total operating expenses		303,869			271,971			203,417
Operating income (loss)		(106,470	)		108,626			55,752
Other income (expense)
Interest expense		(61,289	)		(38,805	)		(27,409	)
Net gain (loss) on commodity derivatives		158,753			189,641			(2,566	)
Other income (expense)		(2,852	)		(7,624	)		(3,443	)
Other income (expense), net		94,612			143,212			(33,418	)
Income (loss) before income tax		(11,858	)		251,838			22,334
Income tax provision (benefit)
Current		113			53			85
Deferred		(2,894	)		26,165			(156	)
Total income tax provision (benefit)		(2,781	)		26,218			(71	)
Net income (loss)		(9,077	)		225,620			22,405
Net income (loss) attributable to non-controlling interests		(6,696	)		184,484			24,591
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136		$	(2,186	)
Earnings (Loss) per share:
Basic	$	(0.09	)	$	3.28		$	(0.17	)
Diluted	$	(0.09	)	$	3.28		$	(0.17	)
Weighted average shares outstanding:
Basic		26,816			12,526			12,500
Diluted		26,816			12,535			12,500

The accompanying notes are an integral part of these consolidated financial statements.

F-4

Jones Energy, Inc.

Statement of Changes in Stockholders' / Members' Equity

Years Ended December 31, 2015, 2014 and 2013

	Common Stock											Treasury Stock
	Class A					Class B						Class A
																	Members' Equity			Additional Paid-in Capital		Retained (Deficit)/ Earnings			Non-controlling Interest			Total Stockholders' / Members' Equity
(amounts in thousands)	Shares			Value		Shares			Value			Shares		Value
Balance at December 31, 2012		—		$	—		—		$	—			—	$	—		$	428,400		$	—	$	—		$	—		$	428,400
Sale of common stock		12,500			13		36,836			37			—		—			—			172,431		—			—			172,481
Reclassification of members' contributions		—			—		—			—			—		—			(464,037	)		—		—			464,037			—
Stock-compensation expense		—			—		—			—			—		—			10,100			738		—			—			10,838
Distribution to members		—			—		—			—			—		—			(10,000	)		—		—			—			(10,000	)
Net income (loss)		—			—		—			—			—		—			35,537			—		(2,186	)		(10,946	)		22,405
Balance at December 31, 2013		12,500			13		36,836			37			—		—			—			173,169		(2,186	)		453,091			624,124
Treasury stock		(23	)		—		—			—			23		(358	)		—			—		—			—			(358	)
Exchange of Class B shares for Class A shares		117			—		(117	)		—			—		—			—			1,554		—			(1,630	)		(76	)
Stock-compensation expense		—			—		—			—			—		—			—			4,040		—			—			4,040
Vested restricted shares		28			—		—			—			—		—			—			—		—			—			—
Net income (loss)		—			—		—			—			—		—			—			—		41,136			184,484			225,620
Balance at December 31, 2014		12,622			13		36,719			37			23		(358	)		—			178,763		38,950			635,945			853,350
Sale of common stock		12,263			12		—			—			—		—			—			123,189		—			—			123,201
Exchange of Class B shares for Class A shares		5,446			6		(5,446	)		(6	)		—		—			—			54,209		—			(92,393	)		(38,184	)
Stock-compensation expense		67			—		—			—			—		—			—			7,562		—			—			7,562
Vested restricted shares		153			—		—			—			—		—			—			—		—			—			—
Net income (loss)		—			—		—			—			—		—			—			—		(2,381	)		(6,696	)		(9,077	)
Balance at December 31, 2015		30,551		$	31		31,273		$	31			23	$	(358	)	$	—		$	363,723	$	36,569		$	536,856		$	936,852

The accompanying notes are an integral part of these consolidated financial statements.

F-5

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2015, 2014 and 2013

	Year Ended December 31,
(in thousands of dollars)	2015			2014			2013
Cash flows from operating activities
Net income (loss)	$	(9,077	)	$	225,620		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization		205,498			181,669			114,136
Exploration expense		5,250			2,952			14,415
Accretion of ARO liability		1,087			770			608
Amortization of debt issuance costs		6,043			6,878			2,677
Stock compensation expense		7,562			4,040			10,838
Other non-cash compensation expense		455			758			2,719
Amortization of deferred revenue		(1,960	)		(1,154	)		(469	)
(Gain) loss on commodity derivatives		(158,753	)		(189,641	)		2,566
(Gain) loss on sales of assets		3			(297	)		78
Deferred income tax provision		(2,892	)		26,165			(156	)
Other—net		(961	)		376			79
Changes in assets and liabilities
Accounts receivable		64,510			(2,453	)		(56,804	)
Other assets		(251	)		(565	)		163
Accrued interest expense		7,050			7,823			1,891
Accounts payable and accrued liabilities		(54,534	)		2,482			33,427
Net cash provided by operations		69,030			265,423			148,573
Cash flows from investing activities
Additions to oil and gas properties		(311,305	)		(474,619	)		(197,618	)
Acquisition of properties		—			—			(178,173	)
Net adjustments to purchase price of properties acquired		—			15,709			—
Proceeds from sales of assets		41			448			1,607
Acquisition of other property, plant and equipment		(1,101	)		(1,683	)		(1,634	)
Current period settlements of matured derivative contracts		144,145			(3,654	)		7,586
Change in restricted cash		(181	)		(104	)		(45	)
Net cash used in investing		(168,401	)		(463,903	)		(368,277	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		85,000			170,000			220,000
Repayment under long-term debt		(335,000	)		(468,000	)		(172,000	)
Proceeds from senior notes		236,475			500,000			—
Payment of debt issuance costs		(1,556	)		(13,416	)		(683	)
Proceeds from sale of common stock		122,779			—			172,481
Purchase of treasury stock		—			(358	)		—
Net cash provided by financing		107,698			188,226			219,798
Net increase (decrease) in cash		8,327			(10,254	)		94
Cash
Beginning of period		13,566			23,820			23,726
End of period	$	21,893		$	13,566		$	23,820
Supplemental disclosure of cash flow information
Cash paid for interest	$	52,796		$	29,560		$	25,414
Cash paid for income taxes		(155	)		155			—
Change in accrued additions to oil and gas properties		(111,210	)		49,025			41,945
Current additions to ARO		6,349			1,995			1,516

The accompanying notes are an integral part of these consolidated financial statements.

F-6

Jones Energy, Inc.

Notes to the Consolidated Financial Statements

1. Organization and Description of Business

Organization

        Jones Energy, Inc. (the "Company") was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC ("JEH"). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH's business and consolidates the financial results of JEH and its subsidiaries.

        JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital (collectively, the "Pre-IPO owners"). JEH acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties.

        The Company's certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company's initial public offering ("IPO") and can be exchanged (together with a corresponding number of units representing membership interests in JEH ("JEH Units")) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company's stockholders generally. As a result of the IPO and as of February 29, 2016, the Pre-IPO owners had 74.7% and 50.6%, respectively, of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest. Prior to the IPO, JEH owned the controlling interest in the Company; hence all of the net income earned prior to the IPO date is reflected in the net income attributable to non-controlling interests on the Consolidated Statement of Operations for the year ended December 31, 2013.

Description of Business

        The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States. The Company's assets are located within the Anadarko and Arkoma basins of Texas and Oklahoma, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

        During the first quarter of 2015, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the over accrual for production taxes which would have been material to the first quarter of 2015 and could be material to projected 2015 annual results if recorded as an out of period adjustment in such period. Therefore we have revised our Balance Sheet and Consolidated Statement of Operations for the year and quarter ended December 31, 2014, as noted in the table below. This revision had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows for the twelve months ended December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

F-7

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

1. Organization and Description of Business (Continued)

        In addition, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the exchange of Class B shares for Class A shares. Therefore we revised our Consolidated Balance Sheet and Statement of Changes in Stockholders' Equity for the year ended December 31, 2014 as noted in the table below. This revision had no impact on Class A or Class B shares outstanding at December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

Consolidated Balance Sheet:

	December 31, 2014								December 31, 2014
				Production tax		Exchange of Class B shares
(in thousands of dollars)	As Reported								As Revised
Accounts Receivable, Oil and gas sales	$	49,861		$	1,621		—		$	51,482
Deferred tax liabilities	$	27,330	(1)	$	144		—		$	27,474
Additional paid in capital	$	177,133			—	$	1,630		$	178,763
Retained earnings	$	38,682		$	268		—		$	38,950
Non-controlling interest	$	636,366		$	1,209	$	(1,630	)	$	635,945

(1)

Certain prior period amounts have been reclassified to conform to the current presentation.

Consolidated Statements of Operations—for the twelve months ended:

	December 31, 2014						December 31, 2014
				Production tax
(in thousands except per share data)	As Reported						As Revised
Production and ad valorem taxes	$	24,177	(1)	$	(1,621	)	$	22,556
Income tax provision (benefit)	$	26,074		$	144		$	26,218
Net income (loss)	$	224,143		$	1,477		$	225,620
Net income (loss) attributable to non-controlling interests	$	183,275		$	1,209		$	184,484
Net income (loss) attributable to controlling interests	$	40,868		$	268		$	41,136
Earnings (Loss) per share:
Basic	$	3.26		$	0.02		$	3.28
Diluted	$	3.26		$	0.02		$	3.28

(1)

Certain prior period amounts have been reclassified to conform to the current presentation.

F-8

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies

Basis of Presentation

        The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for December 31, 2015 and 2014 and the results of the operations and the cash flows for each of the three years in the period ended December 31, 2014 include the Company and all of its subsidiaries.

        Certain prior period amounts have been reclassified to conform to the current presentation.

Segment Information

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

Use of Estimates

        In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

        Significant assumptions are required in the valuation of proved and unproved oil and natural gas reserves, which affect the Company's estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in the Company's estimates of the net gain or loss on commodity derivative assets and liabilities, fair value associated with business combinations, and asset retirement obligations ("ARO").

Cash

        Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions it does business with, and believes the Company's risk is not significant.

Accounts Receivable

        Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consists at December 31, 2015 and at December 31, 2014 of derivative positions not settled as of the balance sheet date and severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management's best estimate of the amounts that may not be collected. As of December 31, 2015 and 2014, the Company did not have significant allowances for doubtful accounts.

F-9

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Concentration of Risk

        Substantially all of the Company's accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company's overall credit risk in that these entities may be affected similarly by changes in economic and other conditions, including declines in commodity prices. As of December 31, 2015, 68% of Accounts receivable—Oil and gas sales are due from four purchasers and 80% of Accounts receivable—Joint interest owners are due from five working interest owners. As of December 31, 2014, 70% of Accounts receivable—Oil and gas sales were due from five purchasers and 67% of Accounts receivable—Joint interest owners were due from five working interest owners. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales were due from eight purchasers and 77% of Accounts receivable—Joint interest owners were due from five working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company's financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

        The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2015, the largest purchasers were Valero Energy Corp. ("Valero"), ETC Field Services LLC, Plains Marketing LP ("Plains Marketing"), NGL Energy Partners LP, and Unimark LLC, which accounted for approximately 18%, 17%, 16%, 15% and 7% of consolidated oil and gas sales, respectively. During the year ended December 31, 2014, the largest purchasers were Valero Energy Corp. ("Valero"), NGL Energy Partners LP, PVR Midstream LLC ("PVR Midstream"), Plains Marketing LP ("Plains Marketing"), and Monarch Natural Gas LLC which accounted for approximately 22%, 12%, 12%, 10% and 10% of consolidated oil and gas sales, respectively. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria Energy Group Ltd. ("Mercuria"), Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively.

        Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company's purchasers are credit worthy.

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there can be an imbalance between the supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to work interruptions or stoppages, the Company could be materially and adversely affected. Management believes that there are adequate alternative providers of drilling and completion services although it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

F-10

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Oil and Gas Properties

        The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

        Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

        The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use.

        On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

        Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over the life of proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

        The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk- adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

        The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company's unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company's current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration and development activity by other companies on adjacent blocks.

        On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed

F-11

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property, Plant and Equipment

        Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years.

Oil and Gas Sales Payable

        Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

Commodity Derivatives

        The Company records its commodity derivative instruments on the Consolidated Balance Sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the years ended December 31, 2015, 2014 and 2013, the Company elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

        Although the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company's exposure to fluctuations in commodity prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) on the Consolidated Statement of Operations. See Note 7, "Fair Value Measurement," for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

        The Company's asset retirement obligations ("ARO") consist of future plugging and abandonment expenses on oil and natural gas properties. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long- lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments.

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are valued at the estimated sales price and recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company

F-12

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

follows the "sales method" of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. Any such imbalances were not significant as of December 31, 2015.

Income Taxes

        Following its IPO on July 29, 2013, the Company began recording a federal and state income tax liability associated with its status as a corporation. No provision for federal income taxes was recorded prior to the IPO because the taxable income or loss was includable in the income tax returns of the individual partners and members. The Company is also subject to state income taxes. The State of Texas includes in its tax system a franchise tax applicable to the Company and an accrual for franchise taxes is included in the financial statements when appropriate.

        Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

        The Company records a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by the Company and may be challenged by the taxation authorities. The Company follows a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. The Company's policy is to include any interest and penalties recorded on uncertain tax positions as a component of income tax expense. The Company's unrecognized tax benefits or related interest and penalties are immaterial.

Comprehensive Income

        The Company has no elements of comprehensive income other than net income.

Recent Accounting Pronouncements

        In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers," which creates a new topic in the ASC, topic 606, "Revenue from Contracts with Customers." This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14 which deferred the effective

F-13

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. We are currently evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements.

        In January 2015, the FASB issued ASU No. 2015- 01, Income Statement—Extraordinary and Unusual Items. This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30) ("Update 2015-15"), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. The guidance is effective for financial statements issued for annual periods beginning after 15 December 2016, and interim periods within those annual periods. Early adoption is permitted. The guidance may be adopted on either a prospective or retrospective basis. The Company has chosen to early adopt ASU No. 2015-17 for the period ended December 31, 2015. Changes to the balance sheet have been applied on a retrospective basis. Adoption did not have a material impact on the financial position, cash flows or results of operations.

        In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

F-14

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

3. Properties, Plant and Equipment

Oil and Gas Properties

        The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas properties consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	2015			2014
Mineral interests in properties
Unproved	$	75,308		$	94,526
Proved		1,031,669			1,001,194
Wells and equipment and related facilities		1,289,323			1,094,202
		2,396,300			2,189,922
Less: Accumulated depletion and impairment		(760,534	)		(551,062	)
Net oil and gas properties	$	1,635,766		$	1,638,860

        As of December 31, 2015 and 2014, we had no material capitalized costs associated with exploratory wells.

        No interest costs were capitalized in 2015. The Company capitalized less than $0.1 million in interest costs during 2014. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        Depletion of oil and gas properties amounted to $204.2 million, $180.6 million, and $113.3 million for the years ended December 31, 2015, 2014, and 2013, respectively.

        No impairments of proved or unproved properties were recorded in 2015, 2014, or 2013. Certain prior period amounts have been reclassified to conform to the current presentation, include the reclassification of Impairment of oil and gas properties to Exploration in the Consolidated Statement of Operations for the twelve months ended December 31, 2013 relating to lease abandonment charges of $14.4 million for certain leases that the Company did not plan to develop.

Other Property, Plant and Equipment

        Other property, plant and equipment consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	2015			2014
Leasehold improvements	$	1,260		$	1,218
Furniture, fixtures, computers and software		4,090			3,727
Vehicles		1,537			988
Aircraft		910			910
Other		247			219
		8,044			7,062
Less: Accumulated depreciation and amortization		(4,171	)		(3,014	)
Net other property, plant and equipment	$	3,873		$	4,048

F-15

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

3. Properties, Plant and Equipment (Continued)

        Depreciation and amortization of other property, plant and equipment amounted to $1.3 million, $1.1 million, and $0.8 million during the years ended December 31, 2015, 2014 and 2013, respectively.

4. Acquisition of Properties

        No business combinations occurred during the twelve months ended December 31, 2015 and 2014.

        On December 18, 2013, JEH closed on the purchase of certain oil and natural gas properties located in Texas and western Oklahoma from Sabine Mid-Continent, LLC, for a purchase price of $193.5 million (referred to herein as the "Sabine acquisition" or "Sabine"), subject to customary closing adjustments. The acquired assets included both producing properties and undeveloped acreage. The purchase was financed with borrowings under the Revolver. In the second quarter of 2014, the Company made a final determination with the sellers as to the purchase price resulting in a final purchase price of $179.2 million. The amount of the total purchase price allocated to undeveloped oil and gas properties was reduced by these adjustments. The adjustments were retroactively applied to our December 31, 2013 Consolidated Balance Sheet as a reduction to oil and gas properties and an increase in receivables. The adjusted purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	32,964
Proved		147,024
Asset retirement obligations		(824	)
Total purchase price	$	179,164

        The unaudited pro forma results presented below have been prepared to include the effect of the Sabine acquisition on our results of operations for the year ended December 31, 2013. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on January 1, 2013 or to project our results of operations for any future date or period.

			Year Ended December 31, 2013
	Post Acquisition(1)
(in thousands of dollars)			Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses		291		229,648
Operating income		1,074		79,125
Net income		1,074		45,778

(1)

Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

        The acquisition qualified as a business combination. The valuation to determine the fair values were principally based on the discounted cash flows of the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the market at the time of acquisition.

F-16

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

5. Long-Term Debt

        Long-term debt consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	December 31, 2015			December 31, 2014
Revolver	$	110,000		$	360,000
2022 Notes		500,000			500,000
2023 Notes		250,000			—
Total principal amount		860,000			860,000
Less: unamortized discount		(12,088	)		—
Total carrying amount	$	847,912		$	860,000

Senior Unsecured Notes

        On April 1, 2014, JEH and Jones Energy Finance Corp., JEH's wholly-owned subsidiary formed for the sole purpose of co-issuing certain of JEH's debt (together the "Issuers"), sold $500.0 million in aggregate principal amount of the Issuers' 6.75% senior notes due 2022 (the "2022 Notes"). The Company used the net proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding borrowings under the Revolver ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014.

        On February 5, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 2022 Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2022 Notes do not apply to the new 2022 Notes. On February 20, 2015, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $500 million outstanding principal amount of 2022 Notes for an equal amount of new 2022 Notes. The exchange offer expired on March 23, 2015. Tenders of $500 million aggregate principal amount, or 100%, of the 2022 Notes were received.

        On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the "2023 Notes") in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015.

        On November 18, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 2023 Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2023 Notes do not apply to the new 2023 Notes. See Note 15, "Subsequent Events," in the Notes to Consolidated Financial Statements for further discussion.

F-17

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

5. Long-Term Debt (Continued)

        The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

        The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.

        The indentures governing the 2022 Notes and 2023 Notes are substantially similar and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company's restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company's assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the Notes are rated investment grade.

Other Long-Term Debt

        The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the "Revolver") and the Second Lien Term Loan (the "Term Loan"), each of which have been or were amended periodically. On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, increase the borrowing base under the Revolver from $550.0 million to $625.0 million until the next redetermination thereof, and extend the maturity date of the Revolver to November 6, 2019. The Company's oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015. Effective October 8, 2015, the borrowing base was reduced to $510 million during the semi-annual borrowing base re-determination.

        The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be redetermined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such redetermination based primarily on reserve reports using lender commodity price expectations at such time. In light of current commodity prices, it is our expectation that the borrowing base will be reduced during the upcoming redetermination. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

        Interest on the Revolver is calculated, at the Company's option, at either (a) the London Interbank Offered ("LIBO") rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one-month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the year ended December 31, 2015, the average

F-18

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

5. Long-Term Debt (Continued)

interest rate under the Revolver was 2.39% on an average outstanding balance of $144.9 million. For the year ended December 31, 2014, the average interest rate under the Revolver was 2.51% on an average outstanding balance of $333.8 million.

        Total interest and commitment fees under the Revolver were $5.1 million, $9.5 million, and $12.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Total interest and commitment fees under the Term Loan were $3.6 million and $14.7 million for the years ended December 31, 2014 and 2013, respectively.

        Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

•

a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and

•

a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

        As of December 31, 2015, our total leverage ratio is approximately 3.2 and our current ratio is approximately 6.9, as calculated based on the requirements in our covenants. We believe that we are in compliance with all terms of our Revolver and expect to maintain compliance during 2016. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2016 and beyond. In the event it were to became necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as hedge restructuring. While it is our expectation that we will continue to be in compliance with our covenants, no assurance can be given that this will be the case. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

F-19

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

6. Derivative Instruments and Hedging Activities

        The Company had various commodity derivatives in place that could affect its future operations as of December 31, 2015 and 2014, as follows:

Hedging Positions

	December 31, 2015
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.16
	Barrels per month		54,000			194,000			97,119		June 2019
Natural gas swaps	Exercise price	$	3.22		$	6.45		$	4.25
	mmbtu per month		700,000			1,640,000			1,042,857		June 2019
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.18	)
	mmbtu per month		1,190,000			1,730,000			1,360,833		December 2016
Natural gas liquids swaps	Exercise price	$	8.90		$	95.24		$	32.62
	Barrels per month		2,000			112,000			51,792		December 2017

	December 31, 2014
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	75.05		$	100.95		$	84.20
	Barrels per month		45,000			184,054			113,852		December 2018
Natural gas swaps	Exercise price	$	3.37		$	6.45		$	4.40
	mmbtu per month		710,000			1,772,584			1,175,275		December 2018
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.21	)
	mmbtu per month		320,000			980,000			716,667		March 2016
Natural gas liquids swaps	Exercise price	$	8.09		$	95.24		$	42.46
	Barrels per month		2,000			143,000			50,444		December 2017

        The Company recognized a net gain on derivative instruments of $158.8 million and $189.6 million for the years ended December 31, 2015 and 2014, respectively, and a net loss of $2.6 million for the year ended December 31, 2013.

Offsetting Assets and Liabilities

        As of December 31, 2015, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

        Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

        We adopted the guidance requiring disclosure of both gross and net information about financial instruments eligible for netting in the balance sheet under our derivative agreements. The following

F-20

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

6. Derivative Instruments and Hedging Activities (Continued)

table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of December 31, 2015 and December 31, 2014:

(in thousands of dollars)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities		(538	)		527			(11	)		—		(11	)
December 31, 2014
Commodity derivative contracts
Assets	$	208,646		$	(72	)	$	208,574		$	—	$	208,574
Liabilities		(100	)		72			(28	)		—		(28	)

7. Fair Value Measurement

Fair Value of Financial Instruments

        The Company determines fair value amounts using available market information and appropriate valuation methodologies. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

        The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

        Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have strong credit quality.

        Liquidity valuation adjustments are necessary when the Company is not able to observe a recent market price for financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional valuation adjustments; therefore, no liquidity reserve is applied.

F-21

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

7. Fair Value Measurement (Continued)

Valuation Hierarchy

        Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument's categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument's fair value. The three levels are defined as follows:

Level 1	Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date. The Company does not classify any of its financial instruments in Level 1.
Level 2	Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.
Level 3	Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

        The financial instruments carried at fair value as of December 31, 2015 and 2014, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	December 31, 2015
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets		—		93,302		—		93,302
Current liabilities		—		11		—		11
Long-term liabilities		—		—		—		—

	December 31, 2014
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	120,604	$	915	$	121,519
Long-term assets		—		85,162		1,893		87,055
Current liabilities		—		—		—		—
Long-term liabilities		—		—		28		28

F-22

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

7. Fair Value Measurement (Continued)

        The following table represents quantitative information about Level 3 inputs used in the fair value measurement of the Company's commodity derivative contracts as of December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value (000's)		Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	1,428	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$8.90 - $47.25 per barrel

        Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement. The following table presents the changes in the Level 3 financial instruments for the years ended December 31, 2015 and 2014. Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.

(in thousands of dollars)
Balance at December 31, 2013, net	$	(1,235	)
Purchases		668
Settlements		476
Transfers into Level 3		(265	)
Transfers to Level 2		332
Changes in fair value		2,804
Balance at December 31, 2014, net		2,780
Purchases		648
Settlements		(960	)
Transfers into Level 3		—
Transfers to Level 2		(1,367	)
Changes in fair value		327
Balance at December 31, 2015, net	$	1,428

        Transfers from Level 3 to Level 2 represent the Company's natural gas basis swaps for which observable forward curve pricing information has become readily available. Purchases represent natural gas liquid swaps that the Company entered into that do not have observable forward curve pricing information.

F-23

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

7. Fair Value Measurement (Continued)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

        The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements:

	December 31, 2015				December 31, 2014
(in thousands of dollars)	Principal Amount		Fair Value		Principal Amount		Fair Value
Debt:
Revolver	$	110,000	$	110,000	$	360,000	$	360,000
2022 Notes		500,000		260,000		500,000		384,375
2023 Notes		250,000		153,283		—		—

        The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

        The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

        The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

        Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include the Company's estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company's AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company's ARO represent a nonrecurring Level 3 measurement.

        The Company reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company's estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

F-24

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

8. Asset Retirement Obligations

        A summary of the Company's ARO for the years ended December 31, 2015 and 2014 is as follows:

(in thousands of dollars)	2015			2014
ARO liability at beginning of year	$	13,610		$	10,963
Liabilities incurred(1)		6,349			1,995
Accretion of ARO liability		1,087			770
Liabilities settled due to sale of related properties		(19	)		(109	)
Liabilities settled due to plugging and abandonment		(69	)		(55	)
Change in estimate		22			46
ARO liability at end of year		20,980			13,610
Less: Current portion of ARO at end of year		(679	)		(3,074	)
Total long-term ARO at end of year	$	20,301		$	10,536

(1)

Includes $4.7 million to correct immaterial errors originating in 2013 and 2014. In addition to the balance sheet impact noted, Accretion of ARO liability of $0.2 million and Depletion, depreciation, and amortization of $0.6 million were recognized in our statement of operations during the fourth quarter of 2015 as a correcting adjustment. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

9. Stock-based Compensation

Management Unit Awards

        Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membership interests in JEH to members of senior management ("management units"). These awards had various vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. In connection with the IPO, both the vested and unvested management units were converted into the right to receive JEH Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new management units have been awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH units that occurred upon forfeiture.

        The following table summarizes information related to the vesting of management units as of December 31, 2015:

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		274,385		$	15.00
Granted		1,909		$	15.00
Forfeited		(1,909	)	$	15.00
Vested		(85,030	)	$	15.00
Unvested at December 31, 2015		189,355		$	15.00

F-25

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

9. Stock-based Compensation (Continued)

        Stock compensation expense associated with the management units for the years ended December 31, 2015, 2014 and 2013 was $1.3 million, $1.6 million, and $10.7 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. The weighted average grant date fair value of management units was $15.00 per share for the year ended December 31, 2015. Unrecognized expense as of December 31, 2015 for all outstanding management units was $2.8 million and will be recognized over a weighted-average remaining period of 1.2 years.

2013 Omnibus Incentive Plan

        Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the "LTIP"), established in conjunction with the Company's IPO, the Company reserved 3,850,000 shares of Class A common stock for non-employee director, consultant and employee stock-based compensation awards.

        The Company granted (i) performance unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company's non-employee directors under the LTIP during 2014 and 2015.

Restricted Stock Unit Awards

        The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under the LTIP. The fair value of the restricted stock unit awards was based on the value of the Company's Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.

        The following table summarizes information related to the total number of units awarded to officers and employees as of December 31, 2015:

	Restricted Stock Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		324,897		$	17.33
Granted		572,939		$	9.58
Forfeited		(14,995	)	$	12.84
Vested		(125,596	)	$	16.75
Unvested at December 31, 2015		757,245		$	11.65

        Stock compensation expense associated with the employee restricted stock unit awards for the years ended December 31, 2015 and 2014 was $3.1 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. There was no stock compensation expense associated with the employee restricted stock unit awards for the year ended December 31, 2013. The weighted average grant date fair value of restricted stock units was $9.58 per share, and $17.31 per share for the years ended December 31, 2015 and 2014, with no awards made during the year ended December 31, 2013. Unrecognized expense as of December 31, 2015 for all outstanding restricted stock unit awards was $5.9 million and will be recognized over a weighted-average remaining period of 1.1 years.

F-26

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

9. Stock-based Compensation (Continued)

Performance Unit Awards

        The Company has outstanding performance unit awards granted to certain officers of the Company under the LTIP. Upon the completion of the applicable three-year performance period, each officer may vest in a number of performance units. The percent of awarded performance units in which each officer vests at such time, if any, will range from 0% to 200% based on the Company's total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance unit is exchangeable for one share of the Company's Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance units earned. The fair value of the performance units is expensed on a straight-line basis over the applicable three-year performance period.

        The following table summarizes information related to the total number of units awarded to the officers as of December 31, 2015:

	Performance Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		192,998		$	21.65
Granted		361,422		$	10.27
Forfeited		—			—
Vested		(15,232	)	$	14.59
Unvested at December 31, 2015		539,188		$	14.22

        Stock compensation expense associated with the performance unit awards for the years ended December 31, 2015 and 2014 was $2.6 million and $0.9 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. There was no stock compensation expense associated with the performance unit awards for the year ended December 31, 2013. The weighted average grant date fair value of performance unit awards was $10.27 per share, and $21.65 per share for the years ended December 31, 2015 and 2014, with no awards made during the year ended December 31, 2013. Unrecognized expense as of December 31, 2015 for all outstanding performance unit awards was $4.0 million and will be recognized over a weighted-average remaining period of 1.5 years.

        The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate future stock prices for the Company and the components of the peer group. The simulation uses a risk- neutral framework along with the risk-free rate of return, the volatility of each entity, and the correlations of each entity with the other entities in the peer group. A stock price path has been simulated for the Company and each peer company and is used to determine the payout percentages and the stock price of the Company's common stock as of the vesting date. The ending stock price is multiplied by the payout percentage to determine the projected payout, which is then discounted using the risk-free rate of return to the grant date to determine the grant date fair value for that simulation. When enough simulations are generated, the resulting distribution gives a reasonable estimate of the range of future expected stock prices.

F-27

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

9. Stock-based Compensation (Continued)

        The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense during the periods presented:

	2015 Performance Unit Awards			2014 Performance Unit Awards
Stock Price(1)	$	10.11		$	17.07
Beginning Average Stock Price(2)	$	11.56		$	14.78
Expected Volatility(3)		55.13	%		46.95	%
Risk-Free Rate of Return(4)		0.79	%		0.61	%

(1)

Based on the closing price of Jones Energy, Inc. Class A common stock on April 29, 2015 and May 20, 2014.

(2)

Based on the 10 trading days immediately prior to the beginning of the performance period.

(3)

For the 2015 award this is based on the average historical volatilities over the most recent 2.67-year period for the Company and each peer company using daily stock prices through April 29, 2015. The measurement period reflects the 2.67 years remaining in the performance period as of the grant date.

For the 2014 award this is based on the average historical volatilities over the most recent 2.62-year period for the Company and each peer company using daily stock prices through May 20, 2014. The measurement period reflects the 2.62 years remaining in the performance period as of the grant date.

(4)

Based on the yield curve of U.S. Treasury rates as of April 29, 2015 and May 20, 2014.

        Based on these assumptions, the Monte Carlo simulation model resulted in an expected percentage of performance units earned of 101.61% and 126.80% for the 2015 and 2014 awards, respectively.

Restricted Stock Awards

        The Company has outstanding restricted stock awards granted to the Company's non-employee members of the Board of Directors under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company's Class A common stock on the date of grant.

F-28

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

9. Stock-based Compensation (Continued)

        The following table summarizes information related to the total value of the awards to the Board of Directors as of December 31, 2015:

	Restricted Stock Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		27,430		$	18.77
Granted		67,380		$	7.30
Forfeited		—			—
Vested		(27,430	)	$	18.77
Unvested at December 31, 2015		67,380		$	7.30

        Stock compensation expense associated with the Board of Directors awards for the years ended December 31, 2015, 2014 and 2013 was $0.6 million, $0.4 million, and $0.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. The weighted average grant date fair value of restricted stock awards was $7.30 per share, $18.77 per share, and $15.05 per share for the years ended December 31, 2015, 2014 and 2013. Unrecognized expense as of December 31, 2015 for all outstanding restricted stock awards was $0.2 million and will be recognized over the remaining vesting period of 0.4 years.

        For the years ended December 31, 2015, 2014, and 2013, the Company had an associated tax benefit of $1.1 million, $0.4 million, and $0.1 million, respectively, related to all stock-based compensation, calculated at the federal statutory rate after adjusting for the non-controlling interest.

10. Benefit Plans

        The Company established a tax-qualified 401(k) savings plan (the "Plan") for the benefit of employees. The Plan is a defined contribution plan and the Company may match a portion of employee contributions to the Plan. In addition, during 2013, the Company established a non-qualified deferred compensation plan for the benefit of key employees. The non-qualified deferred compensation plan is an unfunded, account-based plan under which key employees of the Company may elect to defer a portion of their base salary and/or bonus. For the year ended December 31, 2015, our total expense relating to these plans was $0.5 million. Our total expense relating to these plans for each of the years ended December 31, 2014 and 2013 was $0.3 million.

11. Income Taxes

        Following its IPO, the Company began recording federal and state income tax liabilities associated with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas franchise tax as the Company's taxable income or loss was includable in the income tax returns of the individual partners and members. The Company will recognize a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.

F-29

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

11. Income Taxes (Continued)

        The following table summarizes the tax provision for the years ended December 31, 2015, 2014 and 2013:

	Year Ended December 31,
(in thousands of dollars)	2015			2014		2013
Current tax expense:
Federal	$	—		$	53	$	85
State		113			—		—
Total current expense		113			53		85
Deferred tax expense (benefit):
Federal		(1,137	)		22,140		(1,260	)
State		(1,757	)		4,025		1,104
Total deferred expense (benefit)		(2,894	)		26,165		(156	)
Total tax expense (benefit)		(2,781	)	$	26,218	$	(71	)
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819	$	(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399		1,152
Total income tax expense (benefit)		(2,781	)	$	26,218	$	(71	)

        For the pre-IPO period of the year ended December 31, 2013, the reported taxes in the table above relate solely to the Texas franchise tax liability of JEH.

F-30

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

11. Income Taxes (Continued)

        A reconciliation of the Company's provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate of 35%:

(in thousands of dollars)	2015			2014			2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	(11,858	)	$	251,838		$	22,334
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate	$	(4,150	)	$	88,144		$	7,817
Less: Non-controlling interests		2,911			(65,759	)		(9,009	)
Income tax expense (benefit) attributable to controlling interests		(1,239	)		22,385			(1,192	)
State and local income taxes, net of federal benefit		(1,011	)		626			(49	)
Reduction of TRA liability		(694	)		—			—
Equity compensation, shortfall		338			—			—
Change in enacted rate		(650	)		—			—
Change in valuation allowance		2,333			—			—
Other		(237	)		(192	)		18
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819			(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399			1,152
Total income tax expense (benefit)(1)	$	(2,781	)	$	26,218		$	(71	)

(1)

Deferred tax expense of the year ended December 31, 2015 includes the correction of an immaterial error from the year ended December 31, 2014, whereby deferred tax expense was overstated in 2014 and understated in 2015 by $0.9 million. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

        The Company is subject to federal, state, and local income and franchise taxes. As such, deferred income taxes result from temporary differences between the carrying amounts of assets and liabilities of the Company for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates in effect in the years in which those temporary differences are expected to reverse.

        In 2015, Texas enacted legislation that reduced the tax rate from 1.0% to 0.75%. We recorded a tax benefit of $1.7 million as a result of revaluing our deferred tax assets at the newly enacted rate, of which $1.0 million was attributable to the non-controlling interest.

F-31

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

11. Income Taxes (Continued)

        Significant components of the Company's deferred tax assets and deferred tax liabilities consisted of the following:

	As of December 31,
(in thousands of dollars)	2015			2014
Deferred tax assets
Net operating loss	$	9,414		$	8,223
Section 754 election tax basis adjustment		47,100			945
Alternative minimum tax credits		—			53
Other deferred tax asset		505			232
Total deferred tax assets		57,019			9,453
Deferred tax liabilities
Investment in consolidated subsidiary JEH		73,559			29,307
Noncurrent state deferred tax liability		4,099			7,449
Total deferred tax liabilities		77,658			36,756
Net deferred tax assets (liabilities)		(20,639	)		(27,303	)
Valuation allowance		(2,333	)		—
Net deferred tax assets (liabilities)	$	(22,972	)	$	(27,303	)

        The Company has a federal net operating loss carry-forward totaling $24.8 million and state net operating loss carry-forward of $19.5 million, both of which expire between 2033 and 2035. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2015, we have a valuation allowance of $2.3 million as a result of management's assessment of the realizability of deferred tax assets in Oklahoma. Management believes that there will be sufficient future taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards.

        Separate federal and state income tax returns are filed for Jones Energy, Inc. and Jones Energy Holdings, LLC. JEH's Texas franchise tax returns are subject to audit for 2011 through 2015. The tax years 2012 through 2015 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Internal Revenue Service is currently examining the 2013 federal partnership income tax return for JEH.

        Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2015, 2014 and 2013 there was no material liability or expense for the periods then ended recorded for payments of interest and penalties associated with uncertain tax positions or material unrecognized tax positions and the Company's unrecognized tax benefits were not material.

F-32

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

11. Income Taxes (Continued)

Tax Receivable Agreement

        In connection with the IPO, the Company entered into a Tax Receivable Agreement (the "TRA") which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company's Class B common stock held by those owners for shares of the Company's Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings. At the time of an exchange, the company records a liability to reflect the future payments under the TRA.

        The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company's payments under the TRA constituting imputed interest. In the event that the Company records a valuation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as the payment of the TRA liability is dependent on the realizability of the deferred tax assets. As of December 31, 2015, the amount of the TRA liability was reduced by $2.0 million as a result of the valuation allowance recorded against the Company's deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

        As of December 31, 2015 and 2014 the Company had recorded a TRA liability of $38.1 million and $0.8 million, respectively, for the estimated payments that will be made to the pre-IPO members who have exchanged shares along with corresponding deferred tax assets, net of valuation allowance, of $44.8 million and $0.9 million, respectively, as a result of the increase in tax basis generated arising from such exchanges. The increase in the TRA liability was primarily driven by the exchange of 5 million JEH Units and Class B shares of common stock by Metalmark Captial in May of 2015.

        As of December 31, 2015, the Company had not made any payments under the TRA to pre-IPO members who have exchanged JEH units and Class B common stock for Class A common stock. The Company does not anticipate making a material payment under the TRA in 2016.

12. Earnings per Share

        Basic earnings per share ("EPS") is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. Awards of nonvested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the twelve months ended December 31, 2015, 757,245 restricted stock shares, 67,380 restricted stock units and 539,188 performance units were excluded from the calculation as they would have had an anti-dilutive effect. For the twelve months ended December 31, 2014, 27,430 restricted stock shares, 54,656 restricted stock units and 192,998 performance units were excluded from the calculation as they would have had an anti-dilutive effect. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS. 2014 is calculated using the twelve months

F-33

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

12. Earnings per Share (Continued)

ended December 31, 2014. 2013 is calculated for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

Basic Earnings per Share

(in thousands, except per share data)	2015			2014		2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic		26,816			12,526		12,500
Weighted-average number of shares of Class A common stock—diluted		26,816			12,535		12,500
Earnings (loss) per share:
Basic	$	(0.09	)	$	3.28	$	(0.17	)
Diluted	$	(0.09	)	$	3.28	$	(0.17	)

13. Related Parties

Related Party Transactions

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, ("Monarch"), under which Monarch has the first right to gather the natural gas the Company produces from dedicated properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted for gas. The Company produced approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014 and 0.8 MMBoe of natural gas and NGLs for the year ended December 31, 2013, from the properties that became subject to the Monarch agreement. During the years ended December 31, 2014 and 2013, the Company recognized $37.0 million and $10.4 million, respectively, of revenue associated to the aforementioned natural gas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreement transferred from Monarch to Enable Midstream Partners LP, ("Enable"), an unaffiliated third-party. Prior to closing of the transfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year ended December 31, 2015 from the properties that became subject to the Monarch agreement for which the Company recognized $10.6 million of revenue. The revenue, for all years mentioned, is recorded in Oil and gas sales on the Company's Consolidated Statement of Operations. The initial term of the agreement, which remains unchanged by the transfer to Enable, runs for 10 years from the effective date of September 1, 2013.

        At the time the Company entered into the 2013 Monarch agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital

F-34

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

13. Related Parties (Continued)

beneficially owns in excess of five percent of the Company's outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital.

        In the year ended December 31, 2013, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was recorded in general and administration expense on the Company's Consolidated Statement of Operations. As a result of the IPO, this fee is no longer payable to Metalmark.

        In connection with the Company's entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. During the years ended December 31, 2015, 2014 and 2013, the Company amortized $2.0 million, $1.2 million, and $0.5 million, respectively, of the deferred revenue balance. This revenue is recorded in Other revenues on the Company's Consolidated Statement of Operations.

        Following the issuance of the $15 million Monarch equity interests, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity interests was distributed to certain of the pre-IPO owners, which included Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of December 31, 2015, equity interests in Monarch of $1.3 million are included in Other assets on the Company's Consolidated Balance Sheet. During the years ended December 31, 2015 and 2014, equity interests of $0.8 million and $0.5 million, respectively, were distributed to management under the incentive plan. The Company recognized expense of $0.5 million, $0.8 million, and $0.3 million during the years ended December 31, 2015, 2014, and 2013, respectively, in connection with the incentive plan.

        In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company did not incur or capitalize any costs associated with the construction of the pipeline. The Company did, however, incur gathering fees of $0.4 million which were paid to Monarch Oil Pipeline LLC associated with the approximately 0.2 MMBoe of oil production transported under the agreement for the year ended December 31, 2015. These costs are recorded as an offset to Oil and gas sales in the Company's Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company's Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third-parties, after passing through the gathering and transportation system. The Company has reserved capacity of up to 12,000 barrels per day on the system with the potential to increase throughput at a future date. The audit committee of the Board reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

F-35

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

13. Related Parties (Continued)

        In May 2015, the Company received a $0.7 million cash distribution associated with its equity interests in Monarch, which was accounted for following the cost method. The initial cash distribution from Monarch was treated as dividend income and is recorded in Other income (expense).

14. Commitments and Contingencies

Lease obligations

        The Company leases approximately 43,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for all noncancellable operating leases extending beyond one year at December 31, 2015 are as follows:

(in thousands of dollars)
Years Ending December 31,
2016	$	945
2017		1,038
2018		1,101
2019		1,122
2020		377
Thereafter		—
	$	4,583

        Rent expense under operating leases was $1.6 million, $0.9 million and $0.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Litigation

        The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. The Company believes that the final disposition of such current matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

15. Subsequent Events

        On November 18, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 9.25% senior notes due November 2023 (the "2023 Notes"), except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2023 Notes do not apply to the new 2023 Notes. On January 12, 2016, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $250 million outstanding principal amount of 2023 Notes for an equal amount of new 2023 Notes. The exchange offer expired on February 11, 2016. Tenders of $250 million aggregate principal amount, or 100%, of the 2023 Notes were received.

        In January and February 2016, through several open market and privately negotiated purchases, the Company purchased an aggregate principal amount of $170.5 million of its senior unsecured notes. As of February 29, 2016, the Company had purchased $70.5 million principal amount of its 2022 Notes for $27.1 million, and $100 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and

F-36

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

15. Subsequent Events (Continued)

borrowings from its Revolver to fund the note purchases. As a result of these purchases, the Company had aggregate principal amount of senior unsecured notes outstanding of $579.5 million, outstanding borrowings under its revolving credit facility of $185 million, $325 million undrawn on its revolving credit facility, and $46 million in cash as of February 29, 2016.

16. Subsidiary Guarantors

        On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

        The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH's current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are immaterial.

        Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or a restricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any other guarantor.

        The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH's business. In accordance with JEH's limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

        As of December 31, 2015, the Company held approximately 49.4% of the economic interest in JEH, with the remaining 50.6% economic interest held by a group of investors that owned interests in JEH prior to the Company's IPO (the "Existing Owners"). The Existing Owners have no voting rights with respect to their economic interest in JEH.

        The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock. Pursuant to the Company's certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company's stockholders generally.

        In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Existing Owner held. Holders of the Company's Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company's

F-37

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Continued)

16. Subsidiary Guarantors (Continued)

stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

        The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

F-38

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2015

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,448	$	9,325	$	20		$	—		$	21,893
Restricted Cash		—			—		330		—			—			330
Accounts receivable, net
Oil and gas sales		—			—		19,292		—			—			19,292
Joint interest owners		—			—		11,314		—			—			11,314
Other		—			14,444		726		—			—			15,170
Commodity derivative assets		—			124,207		—		—			—			124,207
Other current assets		—			444		1,854		—			—			2,298
Intercompany receivable		12,866			1,161,997		—		—			(1,174,863	)		—
Total current assets		12,966			1,313,540		42,841		20			(1,174,863	)		194,504
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,635,766		—			—			1,635,766
Other property, plant and equipment, net		—			—		3,168		705			—			3,873
Commodity derivative assets		—			93,302		—		—			—			93,302
Other assets		—			17,714		253		—			—			17,967
Investment in subsidiaries		444,362			—		—		—			(444,362	)		—
Total assets	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	388	$	7,079	$	—		$	—		$	7,467
Oil and gas sales payable		—			—		32,408		—			—			32,408
Accrued liabilities		—			15,741		11,600		—			—			27,341
Commodity derivative liabilities		—			11		—		—			—			11
Asset retirement obligations		—			—		679		—			—			679
Intercompany payable		—			—		1,391,838		2,434			(1,394,272	)		—
Total current liabilities		—			16,140		1,443,604		2,434			(1,394,272	)		67,906
Long-term debt		—			847,912		—		—			—			847,912
Deferred revenue		—			11,417		—		—			—			11,417
Asset retirement obligations		—			—		20,301		—			—			20,301
Liability under tax receivable agreement		38,052			—		—		—			—			38,052
Deferred tax liabilities		19,280			3,692		—		—			—			22,972
Total liabilities		57,332			879,161		1,463,905		2,434			(1,394,272	)		1,008,560
Stockholders' / members' equity
Members' equity		—			545,395		218,123		(1,709	)		(761,809	)		—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding		31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding		31			—		—		—			—			31
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		363,723			—		—		—			—			363,723
Retained earnings		36,569			—		—		—			—			36,569
Stockholders' equity		399,996			545,395		218,123		(1,709	)		(761,809	)		399,996
Non-controlling interest		—			—		—		—			536,856			536,856
Total stockholders' equity		399,996			545,395		218,123		(1,709	)		(224,953	)		936,852
Total liabilities and stockholders' equity	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412

F-39

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2014

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	1,000	$	12,436	$	30		$	—		$	13,566
Restricted Cash		—			—		149		—			—			149
Accounts receivable, net
Oil and gas sales		—			—		51,482		—			—			51,482
Joint interest owners		—			—		41,761		—			—			41,761
Other		102			8,788		3,622		—			—			12,512
Commodity derivative assets		—			121,519		—		—			—			121,519
Other current assets		—			451		2,923		—			—			3,374
Intercompany receivable		4,164			1,203,978		—		—			(1,208,142	)		—
Total current assets		4,366			1,335,736		112,373		30			(1,208,142	)		244,363
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,638,860		—			—			1,638,860
Other property, plant and equipment, net		—			—		3,252		796			—			4,048
Commodity derivative assets		—			87,055		—		—			—			87,055
Other assets		—			20,098		254		—			—			20,352
Deferred tax assets		171			—		—		—			—			171
Investment in subsidiaries		233,908			—		—		—			(233,908	)		—
Total assets	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	288	$	136,049	$	—		$	—		$	136,337
Oil and gas sales payable		—			—		70,469		—			—			70,469
Accrued liabilities		—			8,914		10,487		—			—			19,401
Asset retirement obligations		—			—		3,074		—			—			3,074
Intercompany payable		—			—		1,209,630		2,328			(1,211,958	)		—
Total current liabilities		—			9,202		1,429,709		2,328			(1,211,958	)		229,281
Long-term debt		—			860,000		—		—			—			860,000
Deferred revenue		—			13,377		—		—			—			13,377
Commodity derivative liabilities		—			28		—		—			—			28
Asset retirement obligations		—			—		10,536		—			—			10,536
Liability under tax receivable agreement		803			—		—		—			—			803
Deferred tax liabilities		20,237			7,237		—		—			—			27,474
Total liabilities		21,040			889,844		1,440,245		2,328			(1,211,958	)		1,141,499
Stockholders' / members' equity
Members' equity		—			553,045		314,494		(1,502	)		(866,037	)		—
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding		13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,719,499 shares issued and outstanding		37			—		—		—			—			37
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		178,763			—		—		—			—			178,763
Retained earnings		38,950			—		—		—			—			38,950
Stockholders' equity		217,405			553,045		314,494		(1,502	)		(866,037	)		217,405
Non-controlling interest		—			—		—		—			635,945			635,945
Total stockholders' equity		217,405			553,045		314,494		(1,502	)		(230,092	)		853,350
Total liabilities and stockholders' equity	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849

F-40

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	194,555		$	—		$	—		$	194,555
Other revenues		—			1,960			884			—			—			2,844
Total operating revenues		—			1,960			195,439			—			—			197,399
Operating costs and expenses
Lease operating		—			—			41,027			—			—			41,027
Production and ad valorem taxes		—			—			12,130			—			—			12,130
Exploration		—			—			6,551			—			—			6,551
Depletion, depreciation and amortization		—			—			205,407			91			—			205,498
Accretion of ARO liability		—			—			1,087			—			—			1,087
General and administrative		—			13,565			19,707			116			—			33,388
Other operating		—			—			4,188			—			—			4,188
Total operating expenses		—			13,565			290,097			207			—			303,869
Operating income (loss)		—			(11,605	)		(94,658	)		(207	)		—			(106,470	)
Other income (expense)
Interest expense		—			(59,991	)		(1,298	)		—			—			(61,289	)
Net gain on commodity derivatives		—			158,753			—			—			—			158,753
Other income (expense)		1,984			(4,832	)		(4	)		—			—			(2,852	)
Other income (expense), net		1,984			93,930			(1,302	)		—			—			94,612
Income (loss) before income tax		1,984			82,325			(95,960	)		(207	)		—			(11,858	)
Equity interest in income		(4,728	)		—			—			—			4,728			—
Income tax provision
Current		—			113			—			—			—			113
Deferred		(363	)		(2,531	)		—			—			—			(2,894	)
Total Income tax provision (benefit)		(363	)		(2,418	)		—			—			—			(2,781	)
Net income (loss)		(2,381	)		84,743			(95,960	)		(207	)		4,728			(9,077	)
Net income (loss) attributable to non-controlling interests		—			—			—			—			(6,696	)		(6,696	)
Net income (loss) attributable to controlling interests	$	(2,381	)	$	—		$	—		$	—		$	—		$	(2,381	)

F-41

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	378,401		$	—		$	—		$	378,401
Other revenues		—		1,154			1,042			—			—			2,196
Total operating revenues		—		1,154			379,443			—			—			380,597
Operating costs and expenses
Lease operating		—		—			37,760			—			—			37,760
Production and ad valorem taxes		—		—			22,556			—			—			22,556
Exploration		—		—			3,453			—			—			3,453
Depletion, depreciation and amortization		—		—			181,578			91			—			181,669
Accretion of ARO liability		—		—			770			—			—			770
General and administrative		—		4,493			21,181			89			—			25,763
Other operating		—		—			—			—			—			—
Total operating expenses		—		4,493			267,298			180			—			271,971
Operating income (loss)		—		(3,339	)		112,145			(180	)		—			108,626
Other income (expense)
Interest expense		—		(37,295	)		(1,510	)		—			—			(38,805	)
Net gain on commodity derivatives		—		189,641			—			—			—			189,641
Other income (expense)		—		(7,921	)		297			—			—			(7,624	)
Other income (expense), net		—		144,425			(1,213	)		—			—			143,212
Income (loss) before income tax		—		141,086			110,932			(180	)		—			251,838
Equity interest in income		63,197		—			—			—			(63,197	)		—
Income tax provision
Current		53		—			—			—			—			53
Deferred		22,008		4,157			—			—			—			26,165
Total income tax provision		22,061		4,157			—			—			—			26,218
Net income (loss)		41,136		136,929			110,932			(180	)		(63,197	)		225,620
Net income (loss) attributable to non-controlling interests		—		—			—			—			184,484			184,484
Net income (loss) attributable to controlling interests	$	41,136	$	—		$	—		$	—		$	—		$	41,136

F-42

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues		—			469			637			—			—		1,106
Total operating revenues		—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating		—			—			25,129			—			—		25,129
Production and ad valorem taxes		—			—			15,517			—			—		15,517
Exploration		—			—			16,125			—			—		16,125
Depletion, depreciation and amortization		—			—			114,046			90			—		114,136
Accretion of ARO liability		—			—			608			—			—		608
General and administrative		—			4,154			27,490			258			—		31,902
Other operating		—			—			—			—			—		—
Total operating expenses		—			4,154			198,915			348			—		203,417
Operating income (loss)		—			(3,685	)		59,785			(348	)		—		55,752
Other income (expense)
Interest expense		—			(26,288	)		(1,121	)		—			—		(27,409	)
Net gain on commodity derivatives		—			(2,566	)		—			—			—		(2,566	)
Other income (expense)		—			(3,365	)		41			(119	)		—		(3,443	)
Other income (expense), net		—			(32,219	)		(1,080	)		(119	)		—		(33,418	)
Income (loss) before income tax		—			(35,904	)		58,705			(467	)		—		22,334
Equity interest in income		(3,400	)		—			—			—			3,400		—
Income tax provision
Current		85			—			—			—			—		85
Deferred		(1,299	)		1,143			—			—			—		(156	)
Total income tax provision		(1,214	)		1,143			—			—			—		(71	)
Net income (loss)		(2,186	)		(37,047	)		58,705			(467	)		3,400		22,405
Net income (loss) attributable to non-controlling interests		—			—			—			—			24,591		24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	$	—		$	—		$	—		$	—	$	(2,186	)

F-43

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,381	)	$	84,743		$	(95,960	)	$	(207	)	$	4,728		$	(9,077	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(120,398	)		(202,359	)		405,395			197			(4,728	)		78,107
Net cash (used in) / provided by operations		(122,779	)		(117,616	)		309,435			(10	)		—			69,030
Cash flows from investing activities
Additions to oil and gas properties		—			—			(311,305	)		—			—			(311,305	)
Proceeds from sales of assets		—			—			41			—			—			41
Acquisition of other property, plant and equipment		—			—			(1,101	)		—			—			(1,101	)
Current period settlements of matured derivative contracts		—			144,145			—			—			—			144,145
Change in restricted cash		—			—			(181	)		—			—			(181	)
Net cash (used in) / provided by investing		—			144,145			(312,546	)		—			—			(168,401	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			85,000			—			—			—			85,000
Repayment under long-term debt		—			(335,000	)		—			—			—			(335,000	)
Proceeds from senior notes		—			236,475			—			—			—			236,475
Payment of debt issuance costs		—			(1,556	)		—			—			—			(1,556	)
Proceeds from sale of common stock		122,779			—			—			—			—			122,779
Net cash (used in) / provided by financing		122,779			(15,081	)		—			—			—			107,698
Net increase (decrease) in cash		—			11,448			(3,111	)		(10	)		—			8,327
Cash
Beginning of period		100			1,000			12,436			30			—			13,566
End of period	$	100		$	12,448		$	9,325		$	20		$	—		$	21,893

F-44

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	41,136		$	136,929		$	110,932		$	(180	)	$	(63,197	)	$	225,620
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(40,778	)		(326,859	)		344,103			140			63,197			39,803
Net cash (used in) / provided by operations		358			(189,930	)		455,035			(40	)		—			265,423
Cash flows from investing activities
Additions to oil and gas properties		—			—			(474,619	)		—			—			(474,619	)
Net adjustments to purchase price of properties acquired		—			—			15,709			—			—			15,709
Proceeds from sales of assets		—			—			448			—			—			448
Acquisition of other property, plant and equipment		—			—			(1,683	)		—			—			(1,683	)
Current period settlements of matured derivative contracts		—			(3,654	)		—			—			—			(3,654	)
Change in restricted cash		—			—			(104	)		—			—			(104	)
Net cash (used in) / provided by investing		—			(3,654	)		(460,249	)		—			—			(463,903	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			170,000			—			—			—			170,000
Repayment under long-term debt		—			(468,000	)		—			—			—			(468,000	)
Proceeds from senior notes		—			500,000			—			—			—			500,000
Purchases of treasury stock		(358	)		—			—			—			—			(358	)
Payment of debt issuance costs		—			(13,416	)		—			—			—			(13,416	)
Net cash (used in) / provided by financing		(358	)		188,584			—			—			—			188,226
Net increase (decrease) in cash		—			(5,000	)		(5,214	)		(40	)		—			(10,254	)
Cash
Beginning of period		100			6,000			17,650			70			—			23,820
End of period	$	100		$	1,000		$	12,436		$	30		$	—		$	13,566

F-45

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities		2,286			(189,393	)		315,942			733			(3,400	)		126,168
Net cash (used in) / provided by operations		100			(226,440	)		374,647			266			—			148,573
Cash flows from investing activities
Investment in subsidiary		(172,481	)		—			—			—			172,481			—
Additions to oil and gas properties		—			—			(197,618	)		—			—			(197,618	)
Acquisitions of properties		—			—			(178,173	)		—			—			(178,173	)
Proceeds from sales of assets		—			—			963			644			—			1,607
Acquisition of other property, plant and equipment		—			—			(724	)		(910	)		—			(1,634	)
Current period settlements of matured derivative contracts		—			7,586			—			—			—			7,586
Change in restricted cash		—			—			(45	)		—			—			(45	)
Net cash (used in) / provided by investing		(172,481	)		7,586			(375,597	)		(266	)		172,481			(368,277	)
Cash flows from financing activities
Proceeds from investment in JEI		—			172,481			—			—			(172,481	)		—
Proceeds from issuance of long-term debt		—			220,000			—			—			—			220,000
Repayment under long-term debt		—			(172,000	)		—			—			—			(172,000	)
Proceeds from sale of common stock		172,481			—			—			—			—			172,481
Payment of debt issuance costs		—			(683	)		—			—			—			(683	)
Net cash (used in) / provided by financing		172,481			219,798			—			—			(172,481	)		219,798
Net increase (decrease) in cash		100			944			(950	)		—			—			94
Cash
Beginning of period		—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		$	—		$	23,820

F-46

Jones Energy, Inc.
Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Costs Incurred

        Costs incurred for oil and gas property acquisitions, exploration and development for the last three years are as follows:

(in thousands of dollars)	2015		2014		2013
Property acquisitions:
Unproved	$	4,036	$	20,030	$	35,943
Proved		—		10,101		142,230
Exploration		6,551		3,453		16,125
Development		202,342		488,076		240,412
Total costs incurred(1)	$	212,929	$	521,660	$	434,710

(1)

Excludes the impact of asset retirement costs.

Capitalized Costs

        Capitalized costs for our oil and gas properties consisted of the following at the end of each of the following years:

(in thousands of dollars)	2015			2014
Unproved properties	$	75,308		$	94,526
Proved properties		2,320,992			2,095,396
		2,396,300			2,189,922
Accumulated depletion and impairment		(760,534	)		(551,062	)
Net capitalized costs	$	1,635,766		$	1,638,860

Reserves

        Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves (including natural gas liquids) is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

        The following tables set forth the Company's total proved reserves and the changes in the Company's total proved reserves. These reserve estimates are based in part on reports prepared by Cawley, Gillespie & Associates, Inc. ("Cawley Gillespie"), independent petroleum engineers, utilizing data compiled by us. In preparing its reports, Cawley Gillespie evaluated properties representing all of the Company's proved reserves at December 31, 2015, 2014 and 2013. The Company's proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be

F-47

economically producible in future years from known oil and natural gas reservoirs under existing economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

	Crude Oil (MBbls)			NGL (MBbls)			Natural Gas (MMcf)			Total (MBoe)(1)
Estimated Proved Reserves
December 31, 2012		12,540			34,746			228,080			85,300
Extensions and discoveries		3,786			5,710			39,799			16,129
Production		(1,557	)		(1,724	)		(17,575	)		(6,210	)
Purchases of minerals in place		3,275			4,418			35,023			13,530
Sales of minerals in place		—			—			583			97
Revisions of previous estimates		(1,356	)		(10,235	)		(49,262	)		(19,801	)
December 31, 2013		16,688			32,915			236,648			89,045
Extensions and discoveries		9,295			8,675			59,248			27,844
Production		(2,475	)		(2,345	)		(21,922	)		(8,474	)
Purchases of minerals in place		3,180			3,073			22,943			10,077
Sales of minerals in place		—			—			—			—
Revisions of previous estimates		995			(3,448	)		(4,640	)		(3,226	)
December 31, 2014		27,683			38,870			292,277			115,266
Extensions and discoveries		1,793			1,691			11,793			5,450
Production		(2,582	)		(2,618	)		(23,839	)		(9,174	)
Purchases of minerals in place		—			—			—			—
Sales of minerals in place		—			—			—			—
Revisions of previous estimates		(1,486	)		(5,294	)		(18,635	)		(9,885	)
December 31, 2015		25,408			32,649			261,596			101,657

(1)

Barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or natural gas liquids.

        For the year ended December 31, 2015, the Company added 5,450 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our drilling activity during the year. There were no discoveries of proved reserves. The Company's estimated proved reserves were reduced by current year production of 9,174 MBoe. No purchases or sales of minerals in place occurred during the year ended December 31, 2015.

        For the year ended December 31, 2015, the Company had net negative revisions of 9,885 MBoe, of which 56,330 MBoe was related to commodity pricing. The remaining net positive revisions of 46,445 MBoe were primarily related to reduced future development costs and production performance improvements.

        For the year ended December 31, 2014, the Company added 27,844 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our continued drilling activity throughout the year. There were no discoveries of proved reserves. The Company's estimated proved reserves were reduced by current year production of 8,474 MBoe. The Company added 10,077 MBoe through the purchases of minerals in place. Purchases were primarily related to leasing in the Anadarko basin with associated Cleveland proved reserves. No sales of minerals in place occurred during the year ended December 31, 2014.

        For the year ended December 31, 2014, the Company had net negative revisions of 3,226 MBoe, of which 3,534 MBoe was related to production performance in the Woodford basin. The remaining net

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positive revisions of 308 MBoe were primarily related to production performance in the Cleveland basin and other changes.

        For the year ended December 31, 2013, the Company added 16,129 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our continued drilling activity throughout the year. There were no discoveries of proved reserves. The Company's estimated proved reserves were reduced by current year production of 6,210 MBoe. The Company added 13,530 MBoe through the purchases of minerals in place. Purchases were primarily related to properties from the Sabine acquisition. The Company's estimated proved reserves were reduced by the sales of minerals in place. Sales were primarily related to remaining properties in the Barnett Shale.

        For the year ended December 31, 2013, the Company had net negative revisions of 19,801 MBoe, of which 15,518 MBoe was related to the expiration of the Company's JDA with Southridge. The remaining net negative revisions of 4,283 MBoe were due to a combination of production performance in the Cleveland and Woodford, prices and other changes.

	Crude Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBoe)(1)
Estimated Proved Reserves
December 31, 2013
Proved developed		7,129		19,101		139,623		49,501
Proved undeveloped		9,559		13,814		97,025		39,544
Total proved reserves		16,688		32,915		236,648		89,045
December 31, 2014
Proved developed		10,773		22,555		160,877		60,141
Proved undeveloped		16,910		16,315		131,400		55,125
Total proved reserves		27,683		38,870		292,277		115,266
December 31, 2015
Proved developed		11,032		19,670		169,651		58,977
Proved undeveloped		14,376		12,980		91,945		42,680
Total proved reserves		25,408		32,649		261,596		101,657

(1)

Barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or natural gas liquids.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

        The following information was developed utilizing procedures prescribed by FASB Accounting Standards Codification Topic 932, Extractive Industries—Oil and Gas (Topic 932). The "standardized measure of discounted future net cash flows" should not be viewed as representative of the current value of our proved oil and gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance.

        In reviewing the information that follows, the following factors should be taken into account:

•

future costs and sales prices will probably differ from those required to be used in these calculations;

•

actual production rates for future periods may vary significantly from the rates assumed in the calculations;

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•

future tax rates, deductions and credits are calculated under current laws, which may change in future years;

•

a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues.

        Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month periods ended December 31, 2015, 2014 and 2013. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development and production costs based on year-end costs in order to arrive at net cash flows. Use of a 10% discount rate, first-day-of-the-month prices and year-end costs are required by ASC 932.

        In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

        The standardized measure of discounted future net cash flows from the Company's estimated proved oil and natural gas reserves follows:

(in thousands of dollars)	2015			2014			2013
Future cash inflows	$	2,373,971		$	5,038,212		$	3,213,718
Less related future:
Production costs		(821,773	)		(1,216,184	)		(734,974	)
Development costs		(483,060	)		(939,652	)		(549,343	)
Income tax expense		(31,537	)		(199,727	)		(129,497	)
Future net cash flows		1,037,601			2,682,649			1,799,904
10% annual discount for estimated timing of cash flows		(572,821	)		(1,294,553	)		(859,395	)
Standardized measure of discounted future net cash flows	$	464,780		$	1,388,096		$	940,509

        A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:

(in thousands of dollars)	2015			2014			2013
Balance, beginning of period	$	1,388,096		$	940,509		$	782,020
Net change in sales and transfer prices, net of production expenses		(1,063,248	)		98,647			77,280
Changes in estimated future development costs		96,408			(96,245	)		(9,706	)
Sales and transfers of oil and gas produced during the period		(176,301	)		(382,202	)		(224,739	)
Net change due to extensions and discoveries		6,236			442,340			239,844
Net change due to purchases of minerals in place		—			118,562			149,619
Net change due to sales of minerals in place		—			—			(337	)
Net change due to revisions in quantity estimates		(153,689	)		43,032			(168,438	)
Previously estimated development costs incurred during the period		143,560			163,739			110,783
Net change in income taxes		108,409			(36,514	)		(76,965	)
Accretion of discount		120,047			94,051			59,621
Other		(4,738	)		2,177			1,527
Balance, end of period	$	464,780		$	1,388,096		$	940,509

F-50

Supplemental Quarterly Financial Information (Unaudited)

        Following is a summary of the Company's results of operations by quarter for the years ended December 31, 2015, 2014 and 2013.

	2015
(in thousands except per share data)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Full Year
Revenues	$	58,096		$	53,917		$	47,152		$	38,234		$	197,399
Operating income (loss)		(21,838	)		(23,531	)		(32,393	)		(28,708	)		(106,470	)
Net income (loss)		5,696			(51,180	)		34,842			1,565			(9,077	)
Net income (loss) attributable to non-controlling interests		3,508			(32,737	)		21,604			929			(6,696	)
Net income (loss) attributable to controlling interests		2,188			(18,443	)		13,238			636			(2,381	)
Basic earnings per share	$	0.12		$	(0.66	)	$	0.44		$	0.02		$	(0.09	)
Diluted earnings per share	$	0.12		$	(0.66	)	$	0.44		$	0.02		$	(0.09	)

	2014
(in thousands except per share data)	First Quarter		Second Quarter			Third Quarter		Fourth Quarter		Full Year
Revenues	$	98,244	$	106,390		$	100,346	$	75,617	$	380,597
Operating income		34,017		36,114			26,231		12,264		108,626
Net income (loss)		7,708		(11,454	)		50,025		179,343		225,620
Net income (loss) attributable to non-controlling interests		6,339		(9,397	)		40,893		146,649		184,484
Net income (loss) attributable to controlling interests		1,369		(2,057	)		9,132		32,692		41,136
Basic earnings per share	$	0.11	$	(0.16	)	$	0.73	$	2.60	$	3.28
Diluted earnings per share	$	0.11	$	(0.16	)	$	0.73	$	2.60	$	3.28

	2013
(in thousands except per share data)	First Quarter			Second Quarter		Third Quarter			Fourth Quarter			Full Year
Revenues	$	55,480		$	64,526	$	68,851		$	70,312		$	259,169
Operating income		18,047			20,251		12,095			5,359			55,752
Net income (loss)		(1,452	)		48,417		(15,483	)		(9,077	)		22,405
Net income (loss) attributable to non-controlling interests							(14,623	)		(7,751	)		24,591
Net loss attributable to controlling interests							(860	)		(1,326	)		(2,186	)
Basic earnings (loss) per share						$	(0.07	)	$	(0.10	)	$	(0.17	)
Diluted earnings (loss) per share						$	(0.07	)	$	(0.10	)	$	(0.17	)

F-51

EX-10.22

Exhibit 10.22

Execution Version

MASTER ASSIGNMENT, AGREEMENT AND AMENDMENT NO. 9 TO CREDIT AGREEMENT

This MASTER ASSIGNMENT, AGREEMENT AND AMENDMENT NO. 9 TO CREDIT AGREEMENT (this “Agreement”) dated as of November 6, 2014 (the “Effective Date”), is among Jones Energy Holdings, LLC, a Delaware limited liability company (the “Borrower”), Jones Energy, Inc., a Delaware corporation and the parent company of the Borrower (“Jones Parent”), the undersigned subsidiaries of the Borrower as guarantors (together with Jones Parent, collectively, the “Guarantors”), the Lenders (as defined below), Wells Fargo Bank, N.A. (“Wells Fargo”), in its capacity as administrative agent for the Lenders (in such capacity, the “Administrative Agent”), Wells Fargo, Capital One, National Association, MUFG Union Bank, N.A. (formerly known as Union Bank, N.A.), Toronto Dominion (New York) LLC, Credit Agricole Corporate and Investment Bank, JPMorgan Chase Bank, N.A., Comerica Bank, and SunTrust Bank (collectively, the “Assignors” and each an “Assignor”), and BOKF, NA dba Bank of Texas, Citibank, N.A., Barclays Bank PLC, and IBERIABANK (collectively, the “Assignees” and each an “Assignee”).

RECITALS

A.            The Borrower is party to that certain Credit Agreement dated as of December 31, 2009 among the Borrower, the financial institutions party thereto from time to time as lenders (the “Lenders”) and the Administrative Agent, as heretofore amended (as so amended, the “Credit Agreement”).

B.            The Borrower has requested that the Lenders agree to increase the Borrowing Base under the Credit Agreement, and, to provide for part of the increase in the Borrowing Base, the Assignees have agreed to become a party to the Credit Agreement pursuant to the terms hereof, and the Assignors wish to assign certain percentages of their rights and obligations under the Credit Agreement as Lenders to the Assignees pursuant to the terms hereof.

C.            After the assignment and assumption of the rights and obligations as set forth herein have been made effective, the parties hereto wish to, subject to the terms and conditions of this Agreement, (i) increase the Borrowing Base and (ii) amend the Credit Agreement as provided herein.

NOW THEREFORE, in consideration of the premises and the mutual covenants, representations and warranties contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

Section 1.              Defined Terms.  As used in this Agreement, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein.  Unless otherwise specifically defined herein, each term defined in the Credit Agreement, as amended hereby, and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, as amended hereby.

Section 2.              Other Definitional Provisions.  Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Agreement, unless otherwise specified.  The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement.  The term “including” means “including, without limitation,”.  Paragraph headings have been inserted in this Agreement as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Agreement and shall not be used in the interpretation of any provision of this Agreement.

Section 3.              Master Assignment.

(a)           Assignments.  For an agreed consideration, each Assignor hereby irrevocably and severally sells and assigns to each Assignee, without recourse and without representation or warranty other than as expressly provided herein, and each Assignee hereby irrevocably and severally purchases and assumes from each Assignor, subject to the terms hereof and of the Credit Agreement, (i) such percentage in and to all of such Assignor’s respective rights and obligations in its capacity as a Lender under the Credit Agreement (including, without limitation, such percentage interest in the Loans owing to such Assignor and such Assignor’s risk participation and funded participation in Letters of Credit existing as of the date hereof (prior to the effectiveness of this Agreement)) that would result in the Assignors and the Assignees having the respective Maximum Credit Amounts set forth on Annex I attached hereto, and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of such Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other Loan Document or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above.  Each such sale and assignment is without recourse to any Assignor and, except as expressly provided in this Agreement, without representation or warranty by any Assignor.  After giving effect to the sales and assignments pursuant to this Section 3 and after giving effect to the increase in the Borrowing Base set forth in Section 4 below, each Lender’s (including each Assignee’s) Maximum Credit Amount will be as set forth next to its name on Annex I attached hereto.

(b)           Representations and Warranties of Assignors.  Each Assignor (i) represents and warrants that (A) it is the legal and beneficial owner of the interests that it is assigning under clause (a) above, (B) such interests are free and clear of any lien, encumbrance or other adverse claim and (C) it has full power and authority, and has taken all action necessary, to execute and deliver this Agreement and to consummate the transactions contemplated hereby; and (ii) assumes no responsibility with respect to (A) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (B) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (C) the financial condition of the Borrower, its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (D) the performance or observance by the Borrower, its Subsidiaries or Affiliates or any other Person of any of its obligations under any Loan Document.

2

(c)           Representations and Warranties of Assignee.  Each Assignee (i) represents and warrants that (A) it has full power and authority, and has taken all action necessary, to execute and deliver this Agreement and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement (if not already a Lender thereunder), (B) it meets all the requirements to be an assignee under Section 12.04 of the Credit Agreement (subject to such consents, if any, as may be required under Section 12.04 of the Credit Agreement), (C) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of the interests assigned to it hereunder, shall have the obligations of a Lender thereunder, (D) it is sophisticated with respect to decisions to acquire assets of the type represented by the interests assigned to it hereunder and either it, or the person exercising discretion in making its decision to acquire the interests assigned to it hereunder, is experienced in acquiring assets of such type, (E) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 8.01 thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Agreement and to purchase the interests assigned to it hereunder, (F) it has, independently and without reliance upon the Administrative Agent or any Assignor or any other Assignee and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and to purchase the interests assigned to it hereunder, and (G) it has delivered to the Borrower and the Administrative Agent any documentation required to be delivered by it pursuant to the terms of the Credit Agreement; and (ii) agrees that (A) it will, independently and without reliance on the Administrative Agent or any Assignor or any other Assignee, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (B) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

(d)           Payments.  From and after the Effective Date, the Administrative Agent shall make all payments in respect of the interests assigned hereunder (including payments of principal, interest, fees and other amounts) to the relevant Assignors for amounts which have accrued to but excluding the Effective Date and to the relevant Assignees for amounts which have accrued from and after the Effective Date.  To the extent necessary, the Assignors and the Assignees shall make all appropriate adjustments in payments by the Administrative Agent for periods prior to the Effective Date or with respect to the making of the assignments contemplated hereby directly between themselves.

(e)           Consents.  The Borrower, the Administrative Agent and the Issuing Bank hereby consent to the assignments made under this Section 3 to each Assignee.

Section 4.              Increase in the Borrowing Base.  Subject to the terms of this Agreement, as of the Effective Date, the Borrowing Base shall be increased to $625,000,000 and such Borrowing Base shall remain in effect at that level until the effective date of the next Borrowing Base redetermination made in accordance with the terms of the Credit Agreement, as amended hereby.  The parties hereto acknowledge and agree that the Borrowing Base redetermination set forth in this Section 4 shall be and be deemed to be the Scheduled Redetermination of the Borrowing Base under Section 2.07(b) of the Credit Agreement for fall 2014.  Each Assignor’s

3

and each Assignee’s Applicable Percentage of the resulting Borrowing Base, after giving effect to the assignments made pursuant to Section 3 above and the increase in the Borrowing Base set forth in this Section 4, is set forth in Annex II attached hereto.

Section 5.              Amendments to Credit Agreement.

(a)           The Credit Agreement (other than the exhibits and schedules thereto) is hereby amended and restated in its entirety as set forth in Exhibit A attached hereto.

(b)           Exhibits I (Forms of U.S. Tax Compliance Certificates) to the Credit Agreement is hereby deleted in its entirety and replaced with the Exhibit I (Forms of U.S. Tax Compliance Certificates) attached hereto as Exhibit I.

Section 6.              Credit Parties Representations and Warranties.  Each Credit Party represents and warrants that: (a) after giving effect to this Agreement, the representations and warranties of the Borrower and the Guarantors contained in the Credit Agreement, as amended hereby, and the other Loan Documents are true and correct in all material respects (except that such materiality qualifier shall not be applicable to any such representation or warranty that already is qualified or modified by materiality in the text thereof) on and as of the Effective Date as if made on as and as of such date except to the extent that any such representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true and correct in all material respects (except that such materiality qualifier shall not be applicable to any representation or warranty that already is qualified or modified by materiality in the text thereof) as of such earlier date; (b) after giving effect to this Agreement, no Event of Default has occurred and is continuing; (c) the execution, delivery and performance of this Agreement are within the limited liability company power and authority of such Credit Party and have been duly authorized by appropriate limited liability company action and proceedings; (d) this Agreement constitutes the legal, valid, and binding obligation of such Credit Party enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery, performance, validity and enforceability of this Agreement; and (f) the Liens under the Security Instruments are valid and subsisting and secure the Indebtedness (as such Indebtedness may be increased as a result of the transactions contemplated hereby).

Section 7.              Conditions to Effectiveness.  This Agreement shall become effective on the Effective Date and enforceable against the parties hereto upon the occurrence of the following conditions precedent:

(a)           The Administrative Agent, the Arranger and the Lenders shall have received all commitment, facility and agency fees and all other fees and amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder (including, without limitation, the reasonable fees and expenses of Bracewell & Giuliani LLP, as special counsel to the Administrative Agent).

4

(b)           The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of the Borrower and each Guarantor each setting forth resolutions of its board of directors or other appropriate governing body with respect to the authorization of the Borrower or such Guarantor to execute and deliver the Loan Documents to which it is a party and to enter into the transactions contemplated in those documents, the officers of the Borrower or such Guarantor (y) who are authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party and (z) who will, until replaced by another officer or officers duly authorized for that purpose, act as its representative for the purposes of signing documents and giving notices and other communications in connection with this Agreement and the transactions contemplated hereby, specimen signatures of such authorized officers, and the Organizational Documents of the Borrower and such Guarantor, certified as being true and complete, or if applicable, certifying that there has been no change thereto since the date of a previously-delivered certificate of the Secretary or an Assistant Secretary of the Borrower or such Guarantor. The Administrative Agent and the Lenders may conclusively rely on such certificate until the Administrative Agent receives notice in writing from the Borrower to the contrary.

(c)           The Administrative Agent shall have received certificates of the appropriate State agencies with respect to the existence and qualification of the Borrower and each Guarantor in its jurisdiction of formation.

(d)           The Administrative Agent shall have received from each party hereto counterparts (in such number as may be requested by the Administrative Agent) of this Agreement signed on behalf of such party.

(e)           The Administrative Agent shall have received a duly executed Note payable to the order of any Lender requesting a Note in a principal amount equal to its Maximum Credit Amount dated as of the date hereof.

(f)            The Administrative Agent shall have received from each party thereto duly executed counterparts (in such number as may be requested by the Administrative Agent) of reaffirmations and amendments to the mortgages and deeds of trust that the Borrower or any Guarantor has provided to the Administrative Agent prior to the date hereof, each in form and substance satisfactory to the Administrative Agent.  The Administrative Agent shall be reasonably satisfied that such mortgages and deeds of trust, as reaffirmed and amended, create first priority, perfected Liens (subject only to the Liens permitted by Section 9.03 of the Credit Agreement) on at least 80% of the Engineered Value of the Oil and Gas Properties evaluated in the Reserve Report delivered to the Administrative Agent most recently.

(g)           The Administrative Agent shall have received, in form and substance reasonably satisfactory to the Administrative Agent, an opinion of Baker Botts L.L.P., counsel to the Credit Parties.

(h)           Subject to Section 8.12(a) of the Credit Agreement, as amended hereby, the Administrative Agent shall have received title information as the Administrative Agent may reasonably require with respect to the Oil and Gas Properties evaluated in the Reserve Report delivered to the Administrative Agent most recently.

5

(i)            The Administrative Agent shall have received appropriate UCC search reports for the jurisdiction of organization of each Credit Party reflecting no prior Liens (other than Liens permitted by Section 9.03 of the Credit Agreement) encumbering the Properties of the Credit Parties.

(j)            The Administrative Agent shall have received all documentation and other information that is required by regulatory authorities under applicable “know your customer” and anti-money-laundering rules and regulations, including, without limitation, the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)).

(k)           The representations and warranties in this Agreement shall be true and correct in all material respects.

Section 8.              Acknowledgments and Agreements.

(a)           The Borrower acknowledges that on the date hereof all outstanding Indebtedness is payable in accordance with its terms and the Borrower waives any defense, offset, counterclaim or recoupment with respect thereto.

(b)           The Administrative Agent, the Issuing Bank, and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Loan Documents, as amended hereby.  This Agreement shall not constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Loan Documents, as amended hereby, (ii) any of the agreements, terms or conditions contained in any of the Loan Documents, as amended hereby, (iii) any rights or remedies of the Administrative Agent, the Issuing Bank, or any Lender with respect to the Loan Documents, as amended hereby, or (iv) the rights of the Administrative Agent, the Issuing Bank, or any Lender to collect the full amounts owing to them under the Loan Documents, as amended hereby.

(c)           The Borrower, each Guarantor, the Administrative Agent, the Issuing Bank and each Lender do hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledge and agree that the Credit Agreement, as amended hereby, is and remains in full force and effect, and the Borrower and each Guarantor acknowledge and agree that their respective liabilities and obligations under the Credit Agreement, as amended hereby, the Guarantee and Collateral Agreement, and the other Loan Documents are not impaired in any respect by this Agreement.

(d)           From and after the Effective Date, all references to the Credit Agreement in the Loan Documents shall mean the Credit Agreement, as amended by this Agreement.  This Agreement is a Loan Document for the purposes of the provisions of the other Loan Documents.

Section 9.              Reaffirmation of the Guaranty.  Each Guarantor hereby ratifies, confirms, acknowledges and agrees that its obligations under the Guarantee and Collateral Agreement are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations (as defined in the Guarantee and Collateral Agreement), as such Obligations may have been amended by this Agreement, and its execution and delivery of this Agreement does not indicate or establish an approval or consent

6

requirement by such Guarantor under the Guarantee and Collateral Agreement in connection with the execution and delivery of amendments, consents or waivers to the Credit Agreement, the Notes or any of the other Loan Documents.

Section 10.            Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument.  This Agreement may be executed by facsimile or PDF electronic mail signature, and all such signatures shall be effective as originals.

Section 11.            Successors and Assigns.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

Section 12.            Invalidity.  In the event that any one or more of the provisions contained in this Agreement shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement.

Section 13.            Governing Law.  This Agreement shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of Texas.

Section 14.            Entire Agreement. THIS AGREEMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS AGREEMENT, THE NOTES, AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[SIGNATURES BEGIN ON NEXT PAGE]

7

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the day and year first above written.

BORROWER:	JONES ENERGY HOLDINGS, LLC
	By:	/s/ Robert J. Brooks
			Robert J. Brooks
			Executive Vice President, Chief Financial
			Officer, Secretary and Treasurer
GUARANTORS:	JONES ENERGY, INC.
	JONES ENERGY, LLC
	NOSLEY ASSETS, LLC
	Each by:			/s/ Robert J. Brooks
					Robert J. Brooks
					Executive Vice President, Chief
					Financial Officer, Secretary
					and Treasurer

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

ADMINISTRATIVE AGENT/
ISSUING BANK/LENDER/
ASSIGNOR:	WELLS FARGO BANK, N.A.,
	By:	/s/ Paul A. Squires
		Paul A. Squires
		Managing Director

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	MUFG UNION BANK, N.A.
	(formerly known as Union Bank, N.A.)
	By:	/s/ Rachel Bowman
	Name:	Rachel Bowman
	Title:	Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK
	By:	/s/ Dennis Petito
	Name: Dennis Petito
	Title: Managing Director
	By:	/s/ Michael Willis
	Name: Michael Willis
	Title: Managing Director

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	CAPITAL ONE, NATIONAL ASSOCIATION
	By:	/s/ Michael Higgins
	Name: Michael Higgins
	Title: Director

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	JPMORGAN CHASE BANK, N.A.
	By:	/s/ Jo Linda Papadakis
	Name: Jo Linda Papadakis
	Title: Authorized Officer

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	TORONTO DOMINION (NEW YORK) LLC
	By:	/s/ Masood Fikree
	Name: Masood Fikree
	Title: Authorized Signatory

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	COMERICA BANK
	By:	/s/ Jeffery Treadway
	Name: Jeffery Treadway
	Title: Senior Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNOR:	SUNTRUST BANK
	By:	/s/ Shannon Juhan
	Name: Shannon Juhan
	Title: Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNEE:	BOKF, NA dba Bank of Texas
	By:	/s/ Colin Watson
	Name: Colin Watson
	Title: Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNEE:	Citibank, N.A.
	By:	/s/ Cliff Vaz
	Name: Cliff Vaz
	Title: Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNEE:	Barclays Bank PLC
	By:	/s/ Vanessa Kurbatskiy
	Name: Vanessa Kurbatskiy
	Title: Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER/ASSIGNEE:	IBERIABANK
	By:	/s/ Cameron D. Jones
	Name: Cameron D. Jones
	Title: Senior Vice President

Signature Page to

Master Assignment, Agreement and Amendment No. 9 to Credit Agreement

(Jones Energy Holdings, LLC)

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Name of Lender	Applicable Percentage		Maximum Credit Amount
Wells Fargo Bank, N.A.	16.0000000	%	$	160,000,000.00
MUFG Union Bank, N.A.	11.2000000	%	$	112,000,000.00
Credit Agricole Corporate and Investment Bank	11.2000000	%	$	112,000,000.00
Capital One, National Association	11.2000000	%	$	112,000,000.00
JPMorgan Chase Bank, N.A.	11.2000000	%	$	112,000,000.00
Toronto Dominion (New York) LLC	8.0000000	%	$	80,000,000.00
Comerica Bank	8.0000000	%	$	80,000,000.00
SunTrust Bank	8.0000000	%	$	80,000,000.00
BOKF, NA dba Bank of Texas	4.8000000	%	$	48,000,000.00
Citibank, N.A.	3.6000000	%	$	36,000,000.00
Barclays Bank PLC	3.6000000	%	$	36,000,000.00
IBERIABANK	3.2000000	%	$	32,000,000.00
TOTAL	100.0000000	%	$	1,000,000,000.00

ANNEX II

BORROWING BASE AS OF NOVEMBER 6, 2014*

Name of Lender	Applicable Percentage		Applicable Percentage of the Borrowing Base
Wells Fargo Bank, N.A.	16.0000000	%	$	100,000,000.00
MUFG Union Bank, N.A.	11.2000000	%	$	70,000,000.00
Credit Agricole Corporate and Investment Bank	11.2000000	%	$	70,000,000.00
Capital One, National Association	11.2000000	%	$	70,000,000.00
JPMorgan Chase Bank, N.A.	11.2000000	%	$	70,000,000.00
Toronto Dominion (New York) LLC	8.0000000	%	$	50,000,000.00
Comerica Bank	8.0000000	%	$	50,000,000.00
SunTrust Bank	8.0000000	%	$	50,000,000.00
BOKF, NA dba Bank of Texas	4.8000000	%	$	30,000,000.00
Citibank, N.A.	3.6000000	%	$	22,500,000.00
Barclays Bank PLC	3.6000000	%	$	22,500,000.00
IBERIABANK	3.2000000	%	$	20,000,000.00
TOTAL	100.0000000	%	$	625,000,000.00

*Borrowing Base is subject to redetermination pursuant to the terms of the Credit Agreement, as amended.

EXHIBIT A

EXHIBIT A TO

MASTER ASSIGNMENT, AGREEMENT AND AMENDMENT NO. 9 TO CREDIT AGREEMENT

CREDIT AGREEMENT

DATED AS OF

DECEMBER 31, 2009

AMONG

JONES ENERGY HOLDINGS, LLC
AS BORROWER,

JONES ENERGY, INC.

AS PARENT GUARANTOR,

WELLS FARGO BANK, NATIONAL ASSOCIATION,
AS ADMINISTRATIVE AGENT,

AND

THE LENDERS PARTY HERETO

WELLS FARGO SECURITIES, LLC
AS SOLE LEAD ARRANGER AND SOLE BOOKRUNNER

UNION BANK, N.A. AND CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK

AS CO-SYNDICATION AGENTS

CAPITAL ONE, NATIONAL ASSOCIATION AND JPMORGAN CHASE BANK, N.A.

AS CO-DOCUMENTATION AGENTS

TABLE OF CONTENTS

		Page
ARTICLE I
DEFINITIONS AND ACCOUNTING MATTERS
Section 1.01	Terms Defined Above	1
Section 1.02	Certain Defined Terms	1
Section 1.03	Types of Loans and Borrowings	19
Section 1.04	Terms Generally; Rules of Construction	19
Section 1.05	Accounting Terms and Determinations	20
ARTICLE II
THE CREDITS
Section 2.01	Commitments	20
Section 2.02	Loans and Borrowings	21
Section 2.03	Requests for Borrowings	22
Section 2.04	Interest Elections	23
Section 2.05	Funding of Borrowings	24
Section 2.06	Termination and Reduction of Aggregate Maximum Credit Amounts	25
Section 2.07	Borrowing Base	25
Section 2.08	Letters of Credit	28
ARTICLE III
PAYMENTS OF PRINCIPAL AND INTEREST; PREPAYMENTS; FEES
Section 3.01	Repayment of Loans	33
Section 3.02	Interest	33
Section 3.03	Alternate Rate of Interest	34
Section 3.04	Prepayments	35
Section 3.05	Fees	36
ARTICLE IV
PAYMENTS; PRO RATA TREATMENT; SHARING OF SET-OFFS
Section 4.01	Payments Generally; Pro Rata Treatment; Sharing of Set-offs	37
Section 4.02	Presumption of Payment by the Borrower	39
Section 4.03	Certain Deductions by the Administrative Agent	39
Section 4.04	Disposition of Proceeds	39
ARTICLE V
INCREASED COSTS; BREAK FUNDING PAYMENTS; TAXES; ILLEGALITY; DEFAULTING LENDER
Section 5.01	Increased Costs	39
Section 5.02	Break Funding Payments	41
Section 5.03	Taxes	41
Section 5.04	Mitigation Obligations; Replacement of Lenders	45

Section 5.05	Illegality	46
Section 5.06	Defaulting Lender	46
ARTICLE VI
CONDITIONS PRECEDENT
Section 6.01	[Intentionally Omitted]	50
Section 6.02	Each Credit Event	50
ARTICLE VII
REPRESENTATIONS AND WARRANTIES
Section 7.01	Organization; Powers	50
Section 7.02	Authority; Enforceability	51
Section 7.03	Approvals; No Conflicts	51
Section 7.04	Financial Condition; No Material Adverse Change	51
Section 7.05	Litigation	52
Section 7.06	Environmental Matters	52
Section 7.07	Compliance with the Laws and Agreements; No Defaults	53
Section 7.08	Investment Company Act	53
Section 7.09	Taxes	53
Section 7.10	ERISA	54
Section 7.11	Disclosure; No Material Misstatements	54
Section 7.12	Insurance	55
Section 7.13	Restriction on Liens	55
Section 7.14	Subsidiaries	55
Section 7.15	Location of Business and Offices	55
Section 7.16	Properties; Titles, Etc.	55
Section 7.17	Maintenance of Properties	56
Section 7.18	Gas Imbalances, Prepayments	57
Section 7.19	Marketing of Production	57
Section 7.20	Swap Agreements	57
Section 7.21	Use of Loans and Letters of Credit	57
Section 7.22	Solvency	58
Section 7.23	OFAC; Anti-Terrorism; FCPA	58
Section 7.24	Farmout Agreements	59
ARTICLE VIII
AFFIRMATIVE COVENANTS
Section 8.01	Financial Statements; Other Information	59
Section 8.02	Notices of Material Events	62
Section 8.03	Existence; Conduct of Business	63
Section 8.04	Payment of Taxes	63
Section 8.05	Operation and Maintenance of Properties; Farmouts	63
Section 8.06	Insurance	64
Section 8.07	Books and Records; Inspection Rights	64

Section 8.08	Compliance with Laws	64
Section 8.09	Environmental Matters	64
Section 8.10	Further Assurances	65
Section 8.11	Reserve Reports	66
Section 8.12	Title Information	67
Section 8.13	Additional Collateral; Additional Guarantors	68
Section 8.14	ERISA Compliance	69
Section 8.15	Swap Agreements	69
Section 8.16	Marketing Activities	69
Section 8.17	Designation of Senior Debt	70
ARTICLE IX
NEGATIVE COVENANTS
Section 9.01	Financial Covenants	70
Section 9.02	Debt	70
Section 9.03	Liens	72
Section 9.04	Dividends, Distributions and Redemptions	72
Section 9.05	Investments, Loans and Advances	73
Section 9.06	Nature of Business; International Operations	74
Section 9.07	Proceeds of Loans	75
Section 9.08	ERISA Compliance	75
Section 9.09	Sale or Discount of Receivables	75
Section 9.10	Mergers, Etc.	75
Section 9.11	Sale of Properties	76
Section 9.12	Transactions with Affiliates	77
Section 9.13	Subsidiaries	77
Section 9.14	Negative Pledge Agreements; Dividend Restrictions	77
Section 9.15	Gas Imbalances, Take-or-Pay or Other Prepayments	78
Section 9.16	Swap Agreements	78
Section 9.17	Change in Business; Corporate Structure; Accounting Change	81
Section 9.18	Parent Company	82
Section 9.19	Sanctions; FCPA	83
ARTICLE X
EVENTS OF DEFAULT; REMEDIES
Section 10.01	Events of Default	84
Section 10.02	Remedies	86
ARTICLE XI
THE ADMINISTRATIVE AGENT
Section 11.01	Appointment; Powers	87
Section 11.02	Duties and Obligations of Administrative Agent	87
Section 11.03	Action by Administrative Agent	88
Section 11.04	Reliance by Administrative Agent	89

Section 11.05	Subagents	89
Section 11.06	Resignation or Removal of Administrative Agent	89
Section 11.07	Administrative Agent as Lender	90
Section 11.08	No Reliance	90
Section 11.09	Administrative Agent May File Proofs of Claim	91
Section 11.10	Authority of Administrative Agent to Release Collateral and Liens	91
Section 11.11	The Arranger; Other Agents	92
ARTICLE XII
MISCELLANEOUS
Section 12.01	Notices	92
Section 12.02	Waivers; Amendments	93
Section 12.03	Expenses, Indemnity; Damage Waiver	94
Section 12.04	Successors and Assigns	97
Section 12.05	Survival; Revival; Reinstatement	100
Section 12.06	Counterparts; Integration; Effectiveness	101
Section 12.07	Severability	101
Section 12.08	Right of Setoff	102
Section 12.09	GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS	102
Section 12.10	Headings	103
Section 12.11	Confidentiality	103
Section 12.12	Interest Rate Limitation	104
Section 12.13	EXCULPATION PROVISIONS	105
Section 12.14	Collateral Matters; Swap Agreements	105
Section 12.15	No Third Party Beneficiaries	106
Section 12.16	USA Patriot Act Notice	106
Section 12.17	Keepwell	106
Section 12.18	Flood Insurance Regulations	106
Section 12.19	INTEGRATION	107

ANNEXES, EXHIBITS AND SCHEDULES

Annex I	List of Maximum Credit Amounts
Schedule 7.05	Litigation
Schedule 7.06	Environmental Matters
Schedule 7.14	Subsidiaries and Partnerships
Schedule 7.15	Locations of Business and Offices
Schedule 7.18	Gas Imbalances
Schedule 7.19	Marketing Contracts
Schedule 7.20	Swap Agreements
Schedule 7.24	Farmout Agreements
Schedule 9.05	Investments
Exhibit A	Form of Revolving Note
Exhibit B	Form of Borrowing Request
Exhibit C	Form of Interest Election Request
Exhibit D	Form of Compliance Certificate
Exhibit E	Security Instruments
Exhibit F	Form of Assignment and Assumption
Exhibit G	Form of CPDA
Exhibit H	Forms of U.S. Tax Compliance Certificates

This CREDIT AGREEMENT dated as of December 31, 2009 is among: JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, as borrower (the “Borrower”); JONES ENERGY, INC., a Delaware corporation, as the parent company of the Borrower (“Jones Parent”), each of the LENDERS from time to time party hereto; and WELLS FARGO BANK, N.A. (in its individual capacity, “Wells Fargo”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A.       The Borrower has requested that the Lenders provide certain loans to and extensions of credit on behalf of the Borrower.

B.       The Lenders have agreed to make such loans and extensions of credit subject to the terms and conditions of this Agreement.

C.       In consideration of the mutual covenants and agreements herein contained and of the loans, extensions of credit and commitments hereinafter referred to, the parties hereto agree as follows:

ARTICLE I
Definitions and Accounting Matters

Section 1.01          Terms Defined Above.  As used in this Agreement, each term defined above has the meaning indicated above.

Section 1.02          Certain Defined Terms.  As used in this Agreement, the following terms have the meanings specified below:

“ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

“Acquisition Related Costs” means all purchase price payments, earn-out payments, adjustments of purchase price, payments in respect of non-competition agreements, working capital adjustments, and other contingent payments required under the CPDA.

“Acquisition Swap Agreement” has the meaning assigned such term in Section 9.16(d)(i).

“Actual Production Volumes” means, for any given calendar month, the actual volume of production from the Oil and Gas Properties of the Credit Parties for such month.

“Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/100 of 1%) equal to the LIBO Rate for such Interest Period multiplied by the Statutory Reserve Rate.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Affected Loans” has the meaning assigned such term in Section 5.05.

“Affiliate” means with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Aggregate Maximum Credit Amounts” at any time shall equal the sum of the Maximum Credit Amounts, as the same may be reduced or terminated pursuant to Section 2.06.

“Agreement” means this Credit Agreement, as the same may from time to time be amended, modified, supplemented or restated.

“Alpine Releases” means, collectively, (a) the release of all joint interest billings incurred prior to January 1, 2010 by Alpine, Inc., Alpine Energy, LP, and K2X Operating Company, L.P. (collectively, “Alpine”) and (b) the release and forgiveness of amounts owing by Alpine Energy, LP under that certain revolving note between Alpine Energy, LP and Crusader Energy Group, LLC, in each case, as provided in that certain Stipulation of Resolution of

Objections to the Plan dated December 15, 2009, as approved by the Bankruptcy Court under the Confirmation Order.

“Alternate Base Rate” means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1% and (c) the Adjusted LIBO Rate for a one month Interest Period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1.00%, provided that, for purposes of determining the Alternate Base Rate for any day, the Adjusted LIBO Rate for such day shall be based on the rate (rounded upwards, if necessary, to the next 1/100 of 1%) at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, on such day (or the immediately preceding Business Days if such day is not a day on which banks are open for dealings in dollar deposits in the London interbank market).  Any change in the Alternate Base Rate due to a change in the Prime Rate, the Federal Funds Effective Rate or the Adjusted LIBO Rate shall be effective from and including the effective date of such change in the Prime Rate, the Federal Funds Effective Rate or the Adjusted LIBO Rate, respectively.

“Amendment No. 8 Effective Date” means January 29, 2014.

“Amendment No. 9 Effective Date” means November 6, 2014.

“Amendment No. 9” means that certain Master Assignment, Agreement and Amendment No. 9 to Credit Agreement dated as of the Amendment No. 9 Effective Date which amends this Agreement.

“Applicable Margin” means, for any day, with respect to the Commitment Fee or any ABR Loan or Eurodollar Loan, as the case may be, the rate per annum set forth in the Borrowing Base Utilization Grid below based upon the Borrowing Base Utilization Percentage then in effect:

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage	<25.0%		³25.0% <50.0%		³50.0% <75.0%		³75.0% <90.0%		³90%
Eurodollar Loans	1.500	%	1.750	%	2.000	%	2.250	%	2.500	%
ABR Loans	0.500	%	0.750	%	1.000	%	1.250	%	1.500	%
Commitment Fee	0.375	%	0.375	%	0.500	%	0.500	%	0.500	%

Each change in the Applicable Margin shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change.

“Applicable Percentage” means, with respect to any Lender, the percentage of the Aggregate Maximum Credit Amounts represented by such Lender’s Maximum Credit Amount.  The Applicable Percentage of each Lender as of the Amendment No. 9 Effective Date is set forth on Annex I.

“Approved Counterparty” means, at any time and from time to time, (a) any Person engaged in the business of writing Swap Agreements for commodity, interest rate or currency risk that (i) is reasonably acceptable to the Administrative Agent or (ii) has (or the credit support provider with respect to such Person has), at the time the Borrower or any Subsidiary Guarantor enters into a Swap Agreement with such Person, a long term senior unsecured debt credit rating of BBB or better from S&P or Baa or better from Moody’s or (b) any Hedge Bank.

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Approved Petroleum Engineers” means (a) Cawley, Gillespie & Associates, Inc. and (b) any other independent petroleum engineers selected by the Borrower and reasonably acceptable to the Administrative Agent.

“Arranger” means Wells Fargo Securities, LLC, in its capacities as the sole lead arranger and sole bookrunner hereunder.

“Asset Swap” means the concurrent purchase and sale or exchange of any Property (other than proved Oil and Gas Properties) between the Borrower or any Subsidiary Guarantor and another Person for Property having a reasonably equivalent value.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 12.04(b)), and accepted by the Administrative Agent, in the form of Exhibit F or any other form approved by the Administrative Agent.

“Availability” means the amount equal to the aggregate Commitments minus the aggregate Revolving Credit Exposure.

“Availability Period” means the period from and including the Effective Date to but excluding the Termination Date.

“Bank Products” means each and any of the following bank services or products provided to any Credit Party by any Lender or any Affiliate thereof: (a) commercial credit cards, (b) stored value cards and (c) treasury management services (including, without limitation, controlled disbursement, automated clearinghouse transactions, return items, overdrafts and interstate depository network services).

“Bank Product Obligations” means any and all obligations of any Credit Party owing to a Lender or an Affiliate of a Lender in connection with Bank Products, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor); provided that, if the provider of such Bank Products ceases to be a Lender (or an Affiliate of a Lender), then such obligations owing to such provider shall cease to be Bank Product Obligations hereunder or under any other Loan Document.

“Board” means the Board of Governors of the Federal Reserve System of the United States of America or any successor Governmental Authority.

“Borrowing” means Loans of the same Type, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

“Borrowing Base” means, at any time, an amount equal to the amount determined in accordance with Section 2.07, as the same may be adjusted from time to time pursuant to Section 2.07(e), Section 8.12(c) or Section 9.11(d).

“Borrowing Base Deficiency” occurs if at any time the total Revolving Credit Exposures exceeds the lesser of (A) the Aggregate Maximum Credit Amounts and (B) the then effective Borrowing Base.

“Borrowing Base Utilization Percentage” means, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the Revolving Credit Exposures of the Lenders on such day, and the denominator of which is the Borrowing Base in effect on such day.

“Borrowing Request” means a request by the Borrower for a Borrowing in accordance with Section 2.03.

“Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in Houston, Texas are authorized or required by law to remain closed; and if such day relates to a Borrowing or continuation of, a payment or prepayment of principal of or interest on, or a conversion of or into, or the Interest Period for, a Eurodollar Loan or a notice by the Borrower with respect to any such Borrowing or continuation, payment, prepayment, conversion or Interest Period, any day which is also a day on which dealings in dollar deposits are carried out in the London interbank market.

“Capital Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, recorded as capital leases on the balance sheet of the Person liable (whether contingent or otherwise) for the payment of rent thereunder.

“Casualty Event” means any loss, casualty or other insured damage to, or any nationalization, taking under power of eminent domain or by condemnation or similar proceeding of, any Oil and Gas Property of any Credit Party having a fair market value in excess of $5,000,000.

“Change in Control” means the occurrence of any of the following:

(i)            any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934) other than a Permitted Investor

becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934, except that a person or group shall be deemed to have “beneficial ownership” of all securities that such person or group has the right to acquire (such right, an “option right”), whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of 35% or more of the Voting Securities of Jones Parent on a fully-diluted basis (and taking into account all such Voting Securities that such person or group has the right to acquire pursuant to any option right),

(ii)           during any period of 12 consecutive months, a majority of the members of the board of directors or other equivalent Governing Body of Jones Parent cease to be composed of individuals (A) who were members of that board or equivalent Governing Body on the first day of such period, (B) whose election or nomination to that board or equivalent Governing Body was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of that board or equivalent Governing Body or (C) whose election or nomination to that board or other equivalent Governing Body was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of that board or equivalent Governing Body,

(iii)          Jones Parent ceases to be the sole managing member of the Borrower or Jones Parent ceases to Control the Borrower, or

(iv)          any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934) other than a Permitted Investor or Jones Parent becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934, except that a person or group shall be deemed to have “beneficial ownership” of all securities that such person or group has the right to acquire (such right, an “option right”), whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of 35% or more of the Equity Interests of the Borrower on a fully-diluted basis (and taking into account all such Equity Interests that such person or group has the right to acquire pursuant to any option right).

“Change in Law” means the occurrence, after the Amendment No. 8 Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation, or application thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“Collateral” means the Mortgaged Property and all other property of the Credit Parties which is “Collateral” or “Mortgaged Property” (as defined in the Security Instruments) or similar terms used in the Security Instruments.

“Commitment” means, with respect to each Lender, the commitment of such Lender to make Loans and to acquire participations in Letters of Credit hereunder, expressed as an amount representing the maximum aggregate amount of such Lender’s Revolving Credit Exposure hereunder, as such commitment may be (a) modified from time to time pursuant to Section 2.06 and (b) modified from time to time pursuant to assignments by or to  such Lender pursuant to Section 12.04(b).  The amount representing each Lender’s Commitment shall at any time be the lesser of

such Lender’s Maximum Credit Amount and such Lender’s Applicable Percentage of the then effective Borrowing Base.

“Commitment Fee” has the meaning assigned in Section 3.05(a).

“Commodity Exchange Act” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute.

“Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Net Income” means with respect to any Person and its Consolidated Subsidiaries, for any period, the aggregate of the net income (or loss) of such Person and its Consolidated Subsidiaries after allowances for Taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of any Person in which such Person or its Consolidated Subsidiaries have an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of such Person and its Consolidated Subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in cash during such period by such other Person; (b) any extraordinary gains or losses during such period, (c) any non-cash gains or losses attributable to writeups or writedowns of assets during such period, and (d) any gains or losses resulting from sales or dispositions of Oil and Gas Properties outside the ordinary course of business during such period; provided that, for the avoidance of doubt, for purposes of this Agreement, “Consolidated Net Income” of Jones Parent shall be deemed to include net income (or loss) attributable to non-controlling interests in the Borrower.

“Consolidated Subsidiaries” means each Subsidiary of a Person the financial statements of which shall be consolidated with the financial statements of such Person in accordance with GAAP.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise.  “Controlling” and “Controlled” have meanings correlative thereto.

“CPDA” means the Contingent Payment Debt Agreement dated on or about January 1, 2010 between J/M Crusader Acquisition Sub LLC, a Delaware limited liability company, and the other parties thereto in the form attached as Exhibit G and without giving effect to any amendments, modifications or supplements thereto other than as may be approved by the Administrative Agent.

“CPD SPE” means CCPR Sub LLC, a Delaware limited liability company.

“Credit Parties” means the Borrower and the Guarantors.

“Debt” means, for any Person, the sum of the following (without duplication): (a) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (b) all obligations of such Person (whether contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (c) all obligations of such Person to pay the deferred purchase price of property or services (including all reimbursement, payment or other obligations or liabilities of such Person created or arising under any conditional sale or title retention agreement with respect to property used or acquired by such Person but excluding trade accounts payable in the ordinary course of business that are not overdue for a period of more than 90 days or, if overdue for more than 90 days, which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP); (d) all obligations under Capital Leases; (e) all obligations under Synthetic Leases; (f) all Debt (as defined in the other clauses of this definition) of others secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) a Lien on any Property of such Person, whether or not such Debt is assumed by such Person; (g) all Debt (as defined in the other clauses of this definition) of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the Debt (howsoever such assurance shall be made) to the extent of the lesser of the amount of such Debt and the maximum stated amount of such guarantee or assurance against loss; (h) other than gas balancing arrangements in the ordinary course of business obligations to deliver commodities, goods or services, including, without limitation, Hydrocarbons, in consideration of one or more advance payments but only to the extent of such advance payments and only to the extent such commodities, goods or services have not been delivered; (i) any Debt of a partnership for which such Person is liable either by agreement, by operation of law or by a Governmental Requirement but only to the extent of such liability; (j) Disqualified Capital Stock; and (k) the undischarged balance of any production payment created by such Person or for the creation of which such Person

directly or indirectly received payment.  The Debt of any Person shall include all obligations of such Person of the character described above to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is not included as a liability of such Person under GAAP.  Notwithstanding any of the foregoing to the contrary, “Debt” shall not include the Acquisition Related Costs or any obligations under any Swap Agreement or the CPDA.

“Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

“Defaulting Lender” means any Lender, as reasonably determined by the Administrative Agent, that has (a) failed to fund any portion of its Loans or participations in Letters of Credit within three (3) Business Days of the date required to be funded by it hereunder, (b) notified the Borrower, the Administrative Agent, any Issuing Bank or any Lender in writing that it does not intend to comply with any of its funding obligations under this Agreement or has made a public statement to the effect that it does not intend to comply with its funding obligations under this Agreement, (c) failed within three (3) Business Days after request by the Administrative Agent to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Loans and participations in then outstanding Letters of Credit, (d) otherwise failed to pay over to the Administrative Agent or any other Lender any other amount required to be paid by it hereunder within three Business Days of the date when due, unless the subject of a good faith dispute, or (e) become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has a parent company that has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it; provided that, a Lender shall not become a Defaulting Lender solely as the result of the acquisition or maintenance of an ownership interest in such Lender or Person controlling such Lender, or the exercise of control over a Lender or Person controlling such Lender, by a Governmental Authority or an instrumentality thereof.

“Disposition” has the meaning assigned such term in Section 9.11.

“Disqualified Capital Stock” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Debt or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is one year after the earlier of (a) the Maturity Date and (b) the date on which there are no Loans, LC Exposure or other obligations hereunder outstanding and all of the Commitments are terminated.

“dollars” or “$” refers to lawful money of the United States of America.

“Domestic Subsidiary” means any Subsidiary that is organized under the laws of the United States of America or any state thereof or the District of Columbia.

“EBITDAX” means, for any period, the sum of (a) Consolidated Net Income of Jones Parent for such period, plus (b) the following expenses or charges, without duplication and to the extent deducted in calculating such Consolidated Net Income for such period: (i) Interest Expense, (ii) income Taxes, (iii) depreciation, depletion, amortization, exploration expenses, and intangible drilling costs, (iv) other noncash charges and (v) to the extent expensed and recognized in the applicable period, the transaction fees and expenses incurred in connection with the negotiation, execution and closing of this Agreement, any amendments, amendments and restatements or other modifications to this Agreement or any other permitted Debt Incurrence minus (c) all noncash income added to Consolidated Net Income; provided that, EBITDAX for any applicable period shall be calculated on a pro forma basis (with such calculation made in accordance with guidelines for pro forma presentations set forth by the SEC or as otherwise reasonably acceptable to the Administrative Agent) after giving effect to all acquisitions or Dispositions involving proved, developed, producing Oil and Gas Properties (including the acquisition or Dispositions of Equity Interests in any Person owning proved, developed, producing Oil and Gas Properties) made during such period (a “Subject Transaction”), as if such Subject Transaction was consummated on the first day of such period; provided, however, Jones Parent shall not be required to calculate the pro forma effect of any Subject Transaction unless the aggregate purchase price of all Subject Transactions consummated during such period exceeds the Threshold Amount, as hereinafter defined.  For purposes of this definition: (A) “Threshold Amount” means the greater of 5% of the then effective Borrowing Base and $10,000,000 and (B) in calculating the aggregate

purchase price of all Subject Transactions, the purchase price of acquisitions and Dispositions shall be aggregated and not netted.

“Effective Date” means December 31, 2009.

“Engineering Reports” has the meaning assigned such term in Section 2.07(c)(i).

“Engineered Value” means the value attributed to the Oil and Gas Properties in the applicable Reserve Report based upon the discounted present value of the estimated net cash flow to be realized from the production of Hydrocarbons from such Oil and Gas Properties as set forth in such applicable Reserve Report.

“Environmental Laws” means any and all Governmental Requirements pertaining in any way to health, safety the environment or the preservation or reclamation of natural resources, in effect in any and all jurisdictions in which any Credit Party is conducting or at any time has conducted business, or where any Property of any Credit Party is located, including without limitation, the Oil Pollution Act of 1990 (“OPA”), as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, and other environmental conservation or protection Governmental Requirements.  The term “oil” shall have the meaning specified in OPA, the terms “hazardous substance” and “release” (or “threatened release”) have the meanings specified in CERCLA, the terms “solid waste” and “disposal” (or “disposed”) have the meanings specified in RCRA and the term “oil and gas waste” shall have the meaning specified in Section 91.1011 of the Texas Natural Resources Code (“Section 91.1011”); provided, however, that (a) in the event either OPA, CERCLA, RCRA or Section 91.1011 is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment and (b) to the extent the laws of the state or other jurisdiction in which any Property of any Credit Party is located establish a meaning for “oil,” “hazardous substance,” “release,” “solid waste,” “disposal” or “oil and gas waste” which is broader than that specified in either OPA, CERCLA, RCRA or Section 91.1011, such broader meaning shall apply.

“Environmental Permit” means any permit, registration, license, approval, consent, exemption, variance, or other authorization required under or issued pursuant to applicable Environmental Laws.

“Equity Interests” means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such equity interest.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute.

“ERISA Affiliate” means each trade or business (whether or not incorporated) which together with the Borrower or a Subsidiary Guarantor would be deemed to be a “single employer” within the meaning of section 4001(b)(1) of ERISA or subsections (b), (c), (m) or (o) of section 414 of the Code.

“ERISA Event” means (a) a “Reportable Event” described in section 4043 of ERISA and the regulations issued thereunder, (b) the withdrawal of a Borrower or any ERISA Affiliate from a Plan during a plan year in which it was a “substantial employer” as defined in section 4001(a)(2) of ERISA, (c) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under section 4041 of ERISA, (d) the institution of proceedings to terminate a Plan by the PBGC, (e) receipt of a notice of withdrawal liability pursuant to Section 4202 of ERISA or (f) any other event or condition which might constitute grounds under section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan.

“Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the LIBO Rate.

“Event of Default” has the meaning assigned such term in Section 10.01.

“Excepted Liens” means:  (a) Liens for Taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (b) Liens consisting of pledges or deposits required in the ordinary course of business in connection with workers’ compensation, unemployment insurance or other social security, old age pension or public liability obligations; (c) landlord’s liens, operators’, vendors’, carriers’, warehousemen’s,

repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens, in any event, arising by operation of law or under contract in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) Liens in the form of royalties, overriding royalties, net profits interests, production payments, reversionary interests, calls on production, preferential purchase rights and other burdens on or deductions from the proceeds of production, in each case, which are usual and customary in the oil and gas business and which are taken into account in computing the net revenue interests and working interests of the Credit Parties set forth in the most recently delivered Reserve Report upon which the Borrowing Base has been determined and correspondingly deducted in the calculation of discounted present value set forth in such Reserve Report; (e) contractual Liens not otherwise covered under clause (d) above which arise in the ordinary course of business (and not securing indebtedness for borrowed money) under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are usual and customary in the oil and gas business and provided that any such Lien referred to in this clause (e) (1) is for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, (2) is limited to the assets that are the subject of the relevant agreement and does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by a Credit Party or materially impair the value of such Property subject thereto, and (3) does not result in a burden on or a deduction from the proceeds of production or otherwise a reduction in the calculation of discounted present value set forth in the most recently delivered Reserve Report upon which the Borrowing Base has been determined; (f) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies (including any such banker’s liens, rights of set-off or similar rights and remedies that are contractually agreed upon in deposit account agreements, securities account agreements or commodities account agreements entered into in the ordinary course of business) and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by a Credit Party to provide collateral to the depository institution; (g) easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of a Credit Party for the purpose of roads, pipelines, shared facilities, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, zoning restrictions, rights of way, facilities and equipment, that do not secure any monetary obligations and which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by a Credit Party or materially impair the value of such Property subject thereto; (h) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business; and (i) judgment and attachment Liens not giving rise to an Event of Default, provided that any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired and no action to enforce such Lien has been commenced.

“Exchange Agreement” means that certain Exchange Agreement dated as of July 29, 2013 by and among Jones Parent, the Borrower and each of the Members (as defined therein).

“Excluded Subsidiary” means each of (a) JRJ Opco, LLC, a Texas limited liability company, (b) CPD SPE, and (c) each other Domestic Subsidiary that owns no Property other than Equity Interests in Foreign Subsidiaries.

“Excluded Swap Obligation” means, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the guaranty provided by such Guarantor of, or the grant by such Guarantor of a Lien to secure, such Swap Obligation (or any guaranty thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as

defined in the Commodity Exchange Act and the regulations thereunder at the time the guaranty by such Guarantor or the grant of such Lien becomes effective with respect to such Swap Obligation.  If a Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such guaranty or Lien is or becomes illegal.

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, any U.S. withholding Taxes imposed on amounts payable to or for the account of such recipient with respect to an applicable interest in a Loan or Commitment or otherwise under a Loan Document pursuant to a law in effect on the Amendment No. 9 Effective Date or on the date on which (i) such Lender acquires such interest in the Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 5.04(b)) or becomes a party to this Agreement or becomes an Issuing Bank or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 5.03(a) or Section 5.03(c)(i), amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such recipient became a party hereto or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such recipient’s failure to comply with Section 5.03(e) or Section 5.03(f), and (d) any U.S. federal withholding Taxes imposed under FATCA.

“FATCA” means Sections 1471 through 1474 of the Code, as of the Amendment No. 9 Effective Date (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof, any agreements entered into pursuant to Section 1471(b)(1) of the Code and any intergovernmental agreements that implement or modify the foregoing (together with any law implementing such agreements).

“Federal Funds Effective Rate” means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

“Financial Officer” means, for any Person, the chief financial officer, principal accounting officer, vice president of finance, treasurer or controller of such Person.  Unless otherwise specified, all references herein to a Financial Officer means a Financial Officer of the Borrower.

“Financial Statements” means the financial statement or statements referred to in Section 7.04(a).

“Foreign Lender” means a Lender that is not a U.S. Person.

“Foreign Subsidiary” means any Subsidiary other than a Domestic Subsidiary.

“Fronting Exposure” means, at any time there is a Defaulting Lender, with respect to the Issuing Bank, such Defaulting Lender’s Applicable Percentage of the outstanding LC Exposure other than the LC Exposure as to which such Defaulting Lender’s participation obligation has been funded by it, reallocated to other Lenders or cash collateralized in accordance with the terms hereof.

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in the United States of America.

“Governing Body” means the board of directors or other body having the power to direct or cause the direction of the management and policies of a Person that is a corporation, partnership, trust or limited liability company.

“Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government over the Borrower, any Subsidiary, and of their respective

Properties, the Issuing Bank or any Lender (including any supra-national bodies such as the European Union or the European Central Bank).

“Governmental Requirement” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, whether now or hereinafter in effect, including, without limitation, Environmental Laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“Guarantor” means (a) each Subsidiary Guarantor and (b) Jones Parent.

“Guarantee and Collateral Agreement” means, as the context may require or permit, either (a) that certain Guarantee and Collateral Agreement dated as of December 31, 2009 made by each of the Credit Parties in favor of the Administrative Agent, or (b) that certain Guarantee and Collateral Agreement dated as of January 29, 2014 made by Jones Parent in favor of the Administrative Agent, in each case, as the same may be amended, modified or supplemented from time to time.

“Hazardous Material” means any substance regulated or as to which liability might arise under any applicable Environmental Law and including, without limitation:  (a) any chemical, compound, material, product, byproduct, substance or waste defined as or included in the definition or meaning of “hazardous substance,” “hazardous material,” “hazardous waste,” “solid waste,” “toxic waste,” “extremely hazardous substance,” “toxic substance,” “contaminant,” “pollutant,” or words of similar meaning or import found in any applicable Environmental Law; (b) petroleum hydrocarbons, petroleum products, petroleum substances, natural gas, oil, oil and gas waste, crude oil, and any components, fractions, or derivatives thereof; and (c) radioactive materials, asbestos containing materials, polychlorinated biphenyls, or radon.

“Hedge Bank” means any Person that, at the time it enters into a Swap Agreement with the Borrower or any Subsidiary Guarantor, is a Lender or an Affiliate of a Lender.

“Hedge Obligations” means any and all amounts owing or to be owing by any Credit Party (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising, to any Hedge Bank under any Swap Agreement between a Credit Party and such Hedge Bank; provided, however, if such Hedge Bank ceases to be a Lender (or an Affiliate of a Lender), “Hedge Obligations” shall include such obligations only to the extent arising from transactions (i) entered into at the time that such Hedge Bank was a Lender (or an Affiliate of a Lender) under this Agreement or (ii) entered into on or prior to the date hereof with a Person (or an Affiliate of a Person) that is a Lender on the date hereof.

“Hedged Volume” means, as of any date of determination, the aggregate notional volume of commodities covered under all Swap Agreements of the Borrower and the Subsidiary Guarantors then in effect.

“Highest Lawful Rate” means, with respect to each Lender, the maximum nonusurious interest rate, if any, that at any time or from time to time may be contracted for, taken, reserved, charged or received on the Notes or on other Indebtedness under laws applicable to such Lender which are presently in effect or, to the extent allowed by law, under such applicable laws which may hereafter be in effect and which allow a higher maximum nonusurious interest rate than applicable laws allow as of the date hereof.

“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“Indebtedness” means (a) any and all amounts owing or to be owing by any Credit Party (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising) to the Administrative Agent, the Issuing Bank, or any Lender under any Loan Document; (b) Hedge Obligations other than Excluded Swap Obligations; (c) Bank Product Obligations; and (d) all renewals, extensions and/or rearrangements of any of the above.

“Indemnified Taxes” means (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of any Credit Party under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“Interest Election Request” means a request by the Borrower to convert or continue a Borrowing in accordance with Section 2.04.

“Interest Expense” means, for any period, the sum (determined without duplication) of the aggregate gross interest expense of Jones Parent and its Consolidated Subsidiaries, for such period, including to the extent included in interest expense under GAAP:  (a) amortization of debt discount, (b) capitalized interest and (c) the portion of any payments or accruals under Capital Leases allocable to interest expense, plus the portion of any payments or accruals under Synthetic Leases allocable to interest expense whether or not the same constitutes interest expense under GAAP.

“Interest Payment Date” means (a) with respect to any ABR Loan, the last day of each March, June, September and December and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

“Interest Period” means with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, two, three or six months thereafter, as the Borrower may elect; provided, that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period.  For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

“Interim Redetermination” has the meaning assigned such term in Section 2.07(b).

“Interim Redetermination Date” means the date on which a Borrowing Base that has been redetermined pursuant to an Interim Redetermination becomes effective as provided in Section 2.07(d).

“Investment” means, for any Person, any of the following: (a) the acquisition (whether for cash, Property, services or securities or otherwise) of Equity Interests of any other Person, any “short sale” or any sale of any securities at a time when such securities are not owned by the Person entering into such short sale; (b) the making of any deposit with, or advance, loan or capital contribution to, assumption of Debt of, purchase or other acquisition of any other Debt or equity participation or interest in, or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding ninety (90) days representing the purchase price of inventory or supplies sold by such Person in the ordinary course of business); (c) the purchase or acquisition (in one or a series of transactions) of Property of another Person that constitutes a business unit or (d) the entering into of any guarantee of, or other contingent obligation (including the deposit of any Equity Interests to be sold) with respect to, Debt or other liability of any other Person and (without duplication) any amount committed to be advanced, lent or extended to such Person.

“Issuing Bank” means Wells Fargo, in its capacity as the issuer of Letters of Credit hereunder, and its successors in such capacity as provided in Section 2.08(i).  The Issuing Bank may, in its discretion, arrange for one or more Letters of Credit to be issued by Affiliates of the Issuing Bank, in which case the term “Issuing Bank” shall include any such Affiliate with respect to Letters of Credit issued by such Affiliate.

“Jones Parent” has the meaning assigned such term in the introductory paragraph to this Agreement.

“LC Commitment” at any time means Fifty Million dollars ($50,000,000).

“LC Disbursement” means a payment made by the Issuing Bank pursuant to a Letter of Credit.

“LC Exposure” means, at any time, the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all LC Disbursements that have not yet been reimbursed by or on behalf of the Borrower at such time.  The LC Exposure of any Lender at any time shall be its Applicable Percentage of the total LC Exposure at such time.

“Lenders” means the Persons listed on Annex I and any Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

“Letter of Credit” means any letter of credit issued pursuant to this Agreement.

“Letter of Credit Agreements” means all letter of credit applications and other agreements (including any amendments, modifications or supplements thereto) submitted by the Borrower, or entered into by the Borrower, with the Issuing Bank relating to any Letter of Credit.

“LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, the per annum rate appearing on Reuters Screen LIBOR01 Page (or on any successor or substitute page of such service, or any successor to or substitute for such service, providing rate quotations comparable to those currently provided on such page of such service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period; provided that, if the rate set forth on such reference page or provided by such successor or substitute service is less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.  In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing for such Interest Period shall be the rate (rounded upwards, if necessary, to the next 1/100 of 1%) at which dollar deposits of an amount comparable to such Eurodollar Borrowing and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

“Lien” means any interest in Property securing an obligation owed to, or securing a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including but not limited to (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, conditional sale or trust receipt or a lease, consignment or bailment for security purposes or (b) production payments and the like payable out of Oil and Gas Properties.  The term “Lien” shall include easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations on or with respect to real property. For the purposes of this Agreement, a Credit Party shall be deemed to be the owner of any Property which it has acquired or holds subject to a conditional sale agreement, or leases under a financing lease or other arrangement pursuant to which title to the Property has been retained by or vested in some other Person in a transaction intended to create a financing.

“Liquidity” means, as of a date of determination, an amount equal to (a) Availability plus (b) readily and immediately available cash held in deposit accounts (other than any cash collateral posted to secure the LC Exposure as provided in Section 2.08(j)) of any Credit Party; provided that, such deposit accounts and the funds therein shall be unencumbered and free and clear of all Liens and other third party rights other than (i) a Lien in favor of the Administrative Agent pursuant to Security Instruments and (ii) a Lien in favor of the depositary institution holding such deposit accounts arising solely by virtue of such depositary institution’s standard account documentation or any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only such deposit accounts.

“LLC Agreement” means the Third Amended and Restated Limited Liability Company Agreement of the Borrower dated as of July 26, 2013, as in effect on the Amendment No. 8 Effective Date.

“Loan Documents” means this Agreement, the Notes, the Letter of Credit Agreements, the Letters of Credit and the Security Instruments.

“Loans” means the loans made by the Lenders to the Borrower pursuant to this Agreement.

“Majority Lenders” means, (a) if there are two or more Lenders, (i) at any time while no Loans are outstanding and no LC Exposure exists, Lenders having more than fifty percent (50%) of the Aggregate Maximum Credit Amounts, and (ii) at any time while any Loans are outstanding or any LC Exposure exists, Lenders holding more than fifty percent (50%) of the outstanding aggregate principal amount of the Loans and participation interests in Letters of Credit (without regard to any sale by a Lender of a participation in any Loan under Section 12.04(c)), or (b) if there is only one Lender, such Lender; provided that in each case the Maximum Credit Amounts and the

principal amount of the Loans and participation interests in Letters of Credit of the Defaulting Lenders (if any) shall be excluded from the determination of Majority Lenders.

“Material Adverse Effect” means a material adverse change in, or material adverse effect on (a) the business, operations, Property or condition (financial or otherwise) of the Credit Parties taken as a whole, (b) the ability of any Credit Party to perform any of its obligations under any Loan Document, (c) the validity or enforceability of any Loan Document or (d) the rights and remedies of or benefits available to any Secured Party under any Loan Document.

“Material Farmout Agreements” means, as of any date of determination, (a) all farmout agreements under which a Credit Party has earned an interest in a proved, developed and producing Oil and Gas Property or a proved, developed, non-producing Oil and Gas Property, and (b) all other farmout agreements to which any Credit Party is a party that cover proved, undeveloped reserves other than farmout agreements of the type described in this clause (b) that, individually or in the aggregate, cover less than 10% of the Engineered Value of all proved, undeveloped reserves of the Credit Parties set forth in the most recently delivered Reserve Report.

“Material Indebtedness” means Debt (other than the Loans and Letters of Credit) of the Borrower, Jones Parent or any Subsidiary, and obligations of the Borrower or any Subsidiary in respect of one or more Swap Agreements, in an aggregate principal amount exceeding $10,000,000.  For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Borrower or any Subsidiary in respect of any Swap Agreement at any time shall be the Swap Termination Value in respect of such Swap Agreement at such time.

“Material Operating Agreement” means each operating agreement to which any Credit Party is a party that is material to the business, operations, Property or financial condition of such Credit Party.

“Maturity Date” means November 6, 2019.

“Maximum Credit Amount” means, as to each Lender, the amount set forth opposite such Lender’s name on Annex I under the caption “Maximum Credit Amounts”, as the same may be (i) reduced or terminated from time to time in connection with a reduction or termination of the Aggregate Maximum Credit Amounts pursuant to Section 2.06(b) or (ii) modified from time to time pursuant to any assignment permitted by Section 12.04(b).

“Measurement Date” has the meaning assigned such term in Section 9.16(a)(i).

“Moody’s” means Moody’s Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency.

“Mortgaged Property” means any Property owned by any Credit Party which is subject to the Liens existing and to exist under the terms of the Security Instruments.

“New Borrowing Base Notice” has the meaning assigned such term in Section 2.07(d).

“Notes” means the promissory notes of the Borrower described in Section 2.02(d) and being substantially in the form of Exhibit A, together with all amendments, modifications, replacements, extensions and rearrangements thereof.

“OFAC” means The Office of Foreign Assets Control of the U.S. Department of the Treasury.

“Oil and Gas Disposition” means the Disposition of any Oil and Gas Property or any interest therein or any Subsidiary owning Oil and Gas Properties.

“Oil and Gas Properties” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for

use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“Oil and Gas Properties of the Credit Parties” and “Oil and Gas Properties of any Credit Party” means the Oil and Gas Properties owned by the Credit Parties or applicable Credit Party.

“Organizational Documents” means (a) with respect to any corporation, its certificate or articles of incorporation or organization, as amended, and its bylaws, as amended, (b) with respect to any limited partnership, its certificate of limited partnership, as amended, and its partnership agreement, as amended, (c) with respect to any general partnership, its partnership agreement, as amended, and (d) with respect to any limited liability company, its certificate of formation or articles of organization, as amended, and its limited liability company agreement or operating agreement, as amended.

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such recipient and the jurisdiction imposing such Tax (other than connections arising from such recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 5.04(b)).

“Participant” has the meaning set forth in Section 12.04(c).

“Participant Register” has the meaning set forth in Section 12.04(c).

“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

“Permitted Investors” means any of the following:  (a) Metalmark Capital Partners (C) II, L.P., (b) any fund, investment account, or other investment vehicle managed by Metalmark Capital Management II LLC, (c) any Affiliate of Metalmark Capital Partners (C) II, L.P., a majority of whose outstanding Voting Securities are, directly or indirectly, held by Metalmark Capital Partners II GP, L.P., or any individuals that are Affiliates of Metalmark Capital Partners (C) II, L.P., (d) Jones Energy Management, LLC, and (e) any Affiliate of Jones Energy Management, LLC, a majority of whose outstanding Voting Securities are, directly or indirectly, held by Jones Energy Management, LLC.

“Permitted Payments” means, without duplication as to amounts, (a) payments to Jones Parent (i) to pay reasonable accounting, legal, investment banking fees and administrative expenses (including director and officer insurance) of Jones Parent when due and (ii) to pay fees and expenses (including franchise or similar Taxes) required to maintain its corporate existence, customary salary, bonus and other benefits payable to directors, officers and employees of Jones Parent and general corporate overhead expenses of Jones Parent, in each case under the foregoing clause (i) and (ii), to the extent such fees and expenses are attributable to the ownership or operation of the Borrower and its Subsidiaries and (b) dividends or distributions paid to Jones Parent, if applicable, in amounts equal to amounts required for Jones Parent to pay interest and/or principal on Debt that is permitted under Section 9.18 and the proceeds of which have been contributed to the Borrower or any of its Subsidiaries and that has been guaranteed by, or is otherwise considered Debt of, the Borrower incurred in accordance with Section 9.02.

“Permitted Refinancing Debt” means Debt (for purposes of this definition, “new Debt”) incurred in exchange for, or the proceeds of which are used to extend, refinance, renew, replace, defease, discharge, refund or otherwise retire for value, in whole or in part, any other Debt (the “Refinanced Debt”); provided that (a) such new Debt is in an aggregate principal amount not in excess of the sum of (i) the aggregate principal amount then outstanding of the Refinanced Debt and (ii) an amount necessary to pay all accrued (including, for the purposes of defeasance, future

accrued) and unpaid interest on the Refinanced Debt and any fees and expenses, including premiums, related to such exchange or refinancing; (b) such new Debt has a stated maturity no earlier than the sooner to occur of (i) the date that is one year after the Maturity Date (as in effect on the date of incurrence of such new Debt) and (ii) the stated maturity date of the Refinanced Debt; (c) such new Debt has an average life at the time such new Debt is incurred that is no shorter than the shorter of (i) the period beginning on the date of incurrence of such new Debt and ending on the date that is one year after the Maturity Date (as in effect on the date of incurrence of such new Debt) and (ii) the average life of the Refinanced Debt at the time such new Debt is incurred; (d) such new Debt complies with the requirements set forth in clauses (ii) and (iv) of Section 9.02(h); (e) such new Debt is not incurred or guaranteed by a non-Guarantor if the Borrower or a Guarantor is the issuer or is otherwise an obligor on the Refinanced Debt; and (f) if the Refinanced Debt was subordinated in right of payment to the Indebtedness or the guarantees under the Guarantee and Collateral Agreement, such new Debt (and any guarantees thereof) is subordinated in right of payment to the Indebtedness (or, if applicable, the guarantees under the Guarantee and Collateral Agreement) to at least the same extent as the Refinanced Debt.

“Permitted Tax Distributions” means (a) for any calendar year or portion thereof during which the Borrower is a pass-through entity for U.S. federal income Tax purposes, payments and distributions to the holders of Equity Interests of the Borrower, on or prior to each estimated Tax payment date as well as each other applicable due date, in an amount not to exceed the product of (i) the total aggregate taxable income of the Borrower and its Subsidiaries which is allocable to such holders as a result of the operations or activities of the Borrower and its Subsidiaries during the relevant period (determined by disregarding any adjustment to the taxable income of any member or partner of the Borrower that arises under Section 734(b) or Section 743(b) of the Code), multiplied by (ii) the highest combined marginal federal, state and local income Tax rates applicable to any holder of Equity Interests of the Borrower (or, if any of them are themselves a pass-through entity for U.S. federal income Tax purposes, their members or partners) and (b) without duplication, any other payment or distribution permitted by Section 4.4 of the LLC Agreement.

“Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“Plan” means any employee pension benefit plan, as defined in section 3(2) of ERISA, which (a) is currently or hereafter sponsored, maintained or contributed to by the Borrower, a Subsidiary or an ERISA Affiliate or (b) was at any time during the six-year period preceding the date hereof, sponsored, maintained or contributed to by the Borrower, a Subsidiary or an ERISA Affiliate.

“Prime Rate” means the rate of interest per annum publicly announced from time to time by Wells Fargo as its prime rate in effect at its principal office in San Francisco; each change in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective.  Such rate is set by Wells Fargo as a general reference rate of interest, taking into account such factors as Wells Fargo may deem appropriate; it being understood that many of Wells Fargo’s commercial or other loans are priced in relation to such rate, that it is not necessarily the lowest or best rate actually charged to any customer and that Wells Fargo may make various commercial or other loans at rates of interest having no relationship to such rate.  Each change in the Prime Rate will be effective on the date the change is announced within Wells Fargo.

“Projected Target Property PDP Volumes” means the anticipated projected production from proved, developed, producing Target Oil and Gas Properties as determined by the Borrower’s internal engineers.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

“Proposed Borrowing Base” has the meaning assigned to such term in Section 2.07(c)(i).

“Proposed Borrowing Base Notice” has the meaning assigned to such term in Section 2.07(c)(ii).

“Qualified ECP Guarantor” means, in respect of any Swap Obligation, each Credit Party that has total assets exceeding $10,000,000 at the time the relevant guaranty or grant of the relevant Lien becomes effective with respect to such Swap Obligation or such other Person as constitutes an “eligible contract participant” under the Commodity Exchange Act or any regulations promulgated thereunder and can cause another Person to qualify as an “eligible contract participant” at such time by entering into a keepwell under Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

“Quarter-End Production Report” means the report required to be delivered by the Borrower to the Administrative Agent pursuant to Section 8.01(m) with respect to each calendar month that is the last month of a fiscal quarter.

“Recipient” means (a) the Administrative Agent, (b) any Lender, and (c) any Issuing Bank, as applicable.

“Redemption” means with respect to any Debt, the repurchase, redemption, prepayment, repayment, defeasance or any other acquisition or retirement for value (or the segregation of funds with respect to any of the foregoing) of such Debt, in each case prior to its scheduled maturity.  “Redeem” has the correlative meaning thereto.

“Redetermination Date” means, with respect to any Scheduled Redetermination or any Interim Redetermination, the date that the redetermined Borrowing Base related thereto becomes effective pursuant to Section 2.07(d).

“Redetermination Event” means (a) the occurrence of any payment default or other default under any Material Operating Agreement that would cause such Material Operating Agreement to be terminated or that would cause a Credit Party to lose a material right thereunder and such Material Operating Agreement has not been replaced by (or arrangements reasonably satisfactory to the Administrative Agent have not been made to replace such Material Operating Agreement with) a similar Material Operating Agreement reasonably acceptable to the Administrative Agent, or (b) any cancellation, termination, abandonment or transfer of any farmout agreement, or any material rights of the applicable Credit Party thereunder (other than a transfer to another Credit Party), to the extent that such cancellation, termination, abandonment or transfer, individually or in the aggregate, would cause the Credit Parties to cease to have the contractual right to earn an interest in, or to get an assignment of already earned interest in, oil and gas reserves constituting 10% or more of the Engineered Value of all proved, undeveloped reserves of the Credit Parties as set forth in the most recently delivered Reserve Report.

“Register” has the meaning assigned such term in Section 12.04(b)(iv).

“Regulation D” means Regulation D of the Board, as the same may be amended, supplemented or replaced from time to time.

“Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors (including attorneys, accountants and experts) of such Person and such Person’s Affiliates.

“Release” means any depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping, or disposing.

“Remedial Work” has the meaning assigned such term in Section 8.09(a).

“Required Lenders” means, (a) if there are two or more Lenders, (i) at any time while no Loans are outstanding and no LC Exposure exists, Lenders having at least sixty-six and two-thirds percent (66-2/3%) of the Aggregate Maximum Credit Amounts, and (ii) at any time while any Loans are outstanding or any LC Exposure exists, Lenders holding at least sixty-six and two-thirds percent (66-2/3%) of the outstanding aggregate principal amount of the Loans and participation interests in Letters of Credit (without regard to any sale by a Lender of a participation in any Loan under Section 12.04(c)), or (b) if there is only one Lender, such Lender; provided that the Maximum Credit Amounts and the principal amount of the Loans and participation interests in Letters of Credit of the Defaulting Lenders (if any) shall be excluded from the determination of Required Lenders.

“Reserve Report” means a report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of each January 1st (or December 31st) or July 1st (or June 30th), or such other date in the event of an Interim Redetermination, the oil and gas reserves attributable to the Oil and Gas Properties of the Credit Parties, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date, based upon the pricing assumptions consistent with the Administrative Agent’s lending requirements at the time.

“Responsible Officer” means, as to any Person, the Chief Executive Officer, the President, any Financial Officer or any Vice President of such Person.  Unless otherwise specified, all references to a Responsible Officer herein shall mean a Responsible Officer of the Borrower.

“Restricted Party” means a Person (including any country or any government of a country, any agency of the government of a country, and any organization directly or indirectly controlled by any country or its government):

(a)           that is listed on any Sanctions List (whether designated by name or by reason of being included in a class of Person);

(b)           that is domiciled, registered as located or having its main place of business in, or is incorporated under the laws of, a country which is subject to Sanctions Laws; or

(c)           that is directly or indirectly owned or controlled by a Person referred to in (a) or (b) above.

“Restricted Payment” means any dividend or other distribution (whether in cash, securities or other Property) with respect to any Equity Interests in any Person or any payment (whether in cash, securities or other Property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in any Person or any option, warrant or other right to acquire any such Equity Interests in any Person.  For the avoidance of doubt, Acquisition Related Costs and payments required under the CPDA shall not be considered Restricted Payments.

“Revolving Credit Exposure” means, with respect to any Lender at any time, the sum of the outstanding principal amount of such Lender’s Loans and its LC Exposure at such time.

“Sabine Parent Guaranty” means that certain Parent Guaranty dated as of November 22, 2013 by and between Jones Parent and Sabine Mid-Continent LLC.

“Sanctions Authority” means the United Nations, the European Union, any member of the European Union, the United States of America and any governmental authority acting on behalf of any of them in connection with Sanctions Laws.

“Sanctions Laws” means the economic or financial sanctions laws or regulations and trade embargoes, and the prohibitions, restrictive measures, decisions, executive orders or notices from regulators in connection with such economic sanctions laws or regulations and trade embargoes, in each case implemented, adopted, imposed, administered, enacted or enforced by any Sanctions Authority.

“Sanctions List” means any of the lists of specifically designated nationals or designated persons or entities published in connection with Sanctions Laws by any Sanctions Authority.

“Scheduled Redetermination” has the meaning assigned such term in Section 2.07(b).

“Scheduled Redetermination Date” means the date on which a Borrowing Base that has been redetermined pursuant to a Scheduled Redetermination becomes effective as provided in Section 2.07(d).

“SEC” means the Securities and Exchange Commission or any successor Governmental Authority.

“Secured Parties” means, collectively, the Administrative Agent, the Lenders, the Issuing Bank, the Hedge Banks, and the other Persons (if any) the Indebtedness owing to which is or is purported to be secured by the Collateral under the terms of the Security Instruments.

“Security Instruments” means the Guarantee and Collateral Agreement, mortgages, deeds of trust and other agreements and instruments described or referred to in Exhibit E, and any and all other agreements and instruments now or hereafter executed and delivered by any Credit Party as security for the payment or performance of the Indebtedness (other than (a) Swap Agreements with the Lenders or any Affiliate of a Lender, (b) agreements, instruments or other documents entered into for the provision of Bank Products, or (c) assignment, participation or similar agreements between any Lender and any other lender or creditor with respect to any Indebtedness pursuant to this Agreement), as such agreements and instruments may be amended, modified, supplemented or restated from time to time.

“Senior Secured Debt” means all Indebtedness arising under the Loan Documents.

“Senior Unsecured Debt Incurrence” means the incurrence of any senior unsecured Debt of the Borrower, Jones Parent or any Subsidiary permitted under Section 9.02(h).

“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc., and any successor thereto that is a nationally recognized rating agency.

“Statutory Reserve Rate” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject, with respect to the Adjusted LIBO Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board).  Such reserve percentages shall include those imposed pursuant to such Regulation D.  Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation.  The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“Subsidiary” of a Person means (a) a corporation, partnership, joint venture, limited liability company or other business entity of which at least a majority of the outstanding Equity Interests having by the terms thereof ordinary voting power to elect a majority of the board of directors, managers or other Governing Body (irrespective of whether or not at the time Equity Interests of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by such Person or one or more of its Subsidiaries or such Person and one or more of its Subsidiaries, and (b) any partnership of which such Person or any of its Subsidiaries is a general partner.  Unless otherwise indicated herein, each reference to the term “Subsidiary” shall mean a Subsidiary of the Borrower.

“Subsidiary Guarantor” means (a) each existing Domestic Subsidiary of the Borrower other than any Excluded Subsidiary and (b) each future Domestic Subsidiary of the Borrower that guarantees the Indebtedness pursuant to Section 8.13(b).

“Subject Acquisition” has the meaning assigned such term in Section 9.16(d)(i).

“Swap Agreement” means any transaction or agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions, whether or not any such transaction is governed by or subject to any master agreement.  For the avoidance of doubt, (a) a Swap Agreement governed by a master agreement, including any master agreement published by the International Swaps and Derivatives Association, Inc., shall be deemed entered into when such individual Swap Agreement is entered into without regard to the date on which such master agreement is entered into, and (b) any hedge position or hedging arrangement of the type described in the immediately preceding sentence shall be considered a Swap Agreement regardless of whether a written agreement or written confirmation is entered into.

“Swap Event” means the occurrence of any Swap Termination or any modification to any Swap Agreement, in each case to the extent that, after taking into account the net hedging position under all then outstanding Swap Agreements of the Borrower and its Subsidiaries taken as a whole (including any Swap Agreements entered into concurrently with such Swap Termination or modification), such Swap Termination or such modification could reasonably be expected to reduce the Borrowing Base assuming that a redetermination thereof was then being effected (the amount of such reduction being referred to as the “Swap Event Reduction Amount”).

“Swap Event Reduction Amount” has the meaning assigned in the definition of “Swap Event”.

“Swap Obligation” means, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of section 1a(47) of the Commodity Exchange Act.

“Swap Termination” means any assignment, termination, sale or unwind of any hedge position under any Swap Agreement prior to its maturity or the creation of any off-setting position (whether evidenced by a floor, put or Swap Agreement) with respect to any such position.

“Swap Termination Value” means, in respect of any one or more Swap Agreements, after taking into account the effect of any legally enforceable netting agreement relating to such Swap Agreements, (a) for any date on or after the date such Swap Agreements have been closed out and termination value(s) determined in accordance therewith, such termination value(s) and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as

the mark-to-market value(s) for such Swap Agreements, as determined by the counterparties to such Swap Agreements.

“Synthetic Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income Taxes, if the lessee in respect thereof is obligated to either purchase for an amount in excess of, or pay upon early termination an amount in excess of, 80% of the residual value of the Property subject to such operating lease upon expiration or early termination of such lease.

“Target Oil and Gas Properties” has the meaning assigned such term in Section 9.16(d)(i).

“Tax Receivable Agreement” means that certain Tax Receivable Agreement dated as of July 29, 2013 by and among Jones Parent, the Borrower and each of the Members (as defined therein).

“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Termination Date” means the earliest of (i) the Maturity Date, (ii) the date of termination of the Commitments pursuant to Section 2.06 and (iii) the date of termination of the Commitments pursuant to Section 10.02.

“Total Debt” means, at any date, all Debt of Jones Parent and its Consolidated Subsidiaries.

“Total Leverage Ratio” means, as of the last day of each fiscal quarter, the ratio of (a) Total Debt as of such date to (b) EBITDAX for the period of four consecutive fiscal quarters ending on such date.

“Transactions” means the execution, delivery and performance by the Borrower or any Guarantor of this Agreement and each other Loan Document to which it is a party, the borrowing of Loans and the use of the proceeds thereof, the issuance of Letters of Credit hereunder and the grant of Liens by any Credit Party on Mortgaged Properties and other Properties pursuant to the Security Instruments.

“Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Alternate Base Rate or the LIBO Rate.

“U.S. Person” means any Person that is a “United States person” as defined in Section 7701(a)(30) of the Code.

“U.S. Tax Compliance Certificate” has the meaning assigned to such term in Section 5.03(e).

“Voting Securities” means, with respect to any Person, Equity Interests of any class or kind having the power to vote for the election of the members of the Governing Body of such Person.

“Wells Fargo” has the meaning assigned in the introductory paragraph to this Agreement.

Section 1.03          Types of Loans and Borrowings.  For purposes of this Agreement, Loans and Borrowings, respectively, may be classified and referred to by Type (e.g., a “Eurodollar Loan” or a “Eurodollar Borrowing”).

Section 1.04          Terms Generally; Rules of Construction.  The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined.  Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms.  The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”.  The word “will” shall be construed to have the same meaning and effect as the word “shall”.  The word “or” is not exclusive unless expressly provided for otherwise.  Unless the context or express language requires otherwise, (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, restated, supplemented or otherwise modified (subject to any restrictions on such amendments, restatements, supplements or modifications set forth in the Loan Documents), (b) any reference herein to any law shall be construed as referring to such law as amended, modified, codified or reenacted, in

whole or in part, and in effect from time to time, (c) any reference herein to any Person shall be construed to include such Person’s successors and assigns (subject to the restrictions contained in the Loan Documents), (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) with respect to the determination of any time period, the word “from” means “from and including” and the word “to” means “to and including” and (f) any reference herein to Articles, Sections, Annexes, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Annexes, Exhibits and Schedules to, this Agreement.  No provision of this Agreement or any other Loan Document shall be interpreted or construed against any Person solely because such Person or its legal representative drafted such provision.

Section 1.05          Accounting Terms and Determinations.  Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all determinations with respect to accounting matters hereunder shall be made, and all financial statements and certificates and reports as to financial matters required to be furnished to the Administrative Agent or the Lenders hereunder shall be prepared, in accordance with GAAP as then in effect.  Notwithstanding the foregoing, if at any time any change in GAAP or the application thereof (in any event, the “Subject Change”), would affect the computation of any financial ratio or requirement set forth in this Agreement, and either the Borrower or the Majority Lenders shall so request, the Administrative Agent, the Lenders and the Borrower shall negotiate in good faith to amend such ratio or requirement to preserve the original intent thereof in light of such change (subject to the approval of the Majority Lenders); provided that, until so amended, (i) regardless of whether such request is made before or after such Subject Change, such ratio or requirement shall continue to be computed in accordance with GAAP without giving effect to such Subject Change, and (ii) the Borrower shall provide to the Administrative Agent financial statements and other documents required under this Agreement or as reasonably requested hereunder setting forth a reconciliation between calculations of such ratio or requirement made before and after giving effect to such Subject Change. Notwithstanding the foregoing clause (c), for purposes of this Agreement, (i) any lease that was treated as an operating lease under GAAP at the time it was entered into and that later becomes a Capital Lease as a result of the change in GAAP that occurs upon a conversion to International Financial Reporting Standards during the life of such lease, including any renewals, shall be treated as an operating lease for all purposes under this Agreement including the treatment of assets in calculating, among other things, EBITDAX or Debt, and (ii) any lease that is entered into after the occurrence of the change in GAAP discussed in the foregoing clause (i) shall be given the treatment provided for under GAAP, as so amended, for all purposes under this Agreement including the treatment of assets in calculating, among other things, EBITDAX.

ARTICLE II
The Credits

Section 2.01          Commitments.  Subject to the terms and conditions set forth herein, each Lender agrees to make Loans to the Borrower from time to time during the Availability Period in an aggregate principal amount that will not result in (a) such Lender’s Revolving Credit Exposure exceeding such Lender’s Commitment or (b) the total Revolving Credit Exposures exceeding the total Commitments.  Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, repay and reborrow the Loans.

Section 2.02          Loans and Borrowings.

(a)           Borrowings; Several Obligations.  Each Loan shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their respective Commitments.  The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

(b)           Types of Loans.  Subject to Section 3.03, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith.  Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

(c)           Minimum Amounts; Limitation on Number of Borrowings.  At the commencement of each Interest Period for any Eurodollar Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $500,000 and not less than $1,000,000.  At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $100,000 and not less than $500,000; provided that, notwithstanding the foregoing, an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments or that is required to finance the reimbursement of an LC Disbursement as contemplated by Section 2.08(e).  Borrowings of more than one Type may be outstanding at the same time, provided that there shall not at any time be more than a total of ten Eurodollar Borrowings outstanding.  Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled to request, or to elect to convert or continue, any Borrowing if the Interest Period requested with respect thereto would end after the Maturity Date.

(d)           Notes.  Any Lender may request that Loans made by it be evidenced by a Note.  In such event, the Borrower shall prepare, execute and deliver to such Lender a Note, dated, in the case of (i) any Lender party hereto as of the date of this Agreement, as of the date of this Agreement, or (ii) any Lender that becomes a party hereto pursuant to an Assignment and Assumption, as of the effective date of the Assignment and Assumption, payable to such Lender in a principal amount equal to its Maximum Credit Amount as in effect on such date, and otherwise duly completed.  In the event that any Lender’s Maximum Credit Amount increases or decreases for any reason (whether pursuant to Section 2.06, Section 12.04(b) or otherwise), and the Borrower had previously delivered such Lender one or more Notes, such Lender may request a new Note, and in such event the Borrower shall deliver or cause to be delivered on the effective date of such increase or decrease, a new Note payable to such Lender in a principal amount equal to its Maximum Credit Amount after giving effect to such increase or decrease, and otherwise duly completed, against return of the Note(s) so replaced.  The date, amount, Type, interest rate and, if applicable, Interest Period of each Loan made (or deemed to be made) by each Lender, and all payments made on account of the principal thereof, shall be recorded by such Lender on its books for its Note, and, prior to any transfer, may be endorsed by such Lender on a schedule attached to such Note or any continuation thereof or on any separate record maintained by such Lender.  Failure to make any such notation or to attach a schedule shall not affect any Lender’s or

the Borrower’s rights or obligations in respect of such Loans or affect the validity of such transfer by any Lender of its Note.

Section 2.03          Requests for Borrowings.  To request a Borrowing, the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 12:00 noon, Houston, Texas time, three Business Days before the date of the proposed Borrowing or (b) in the case of an ABR Borrowing, not later than 12:00 noon, Houston, Texas time, one Business Day before the date of the proposed Borrowing; provided that no such notice shall be required for any deemed request of an ABR Borrowing to finance the reimbursement of an LC Disbursement as provided in Section 2.08(e).  Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery, telecopy (or by electronic transmittal (e-mail) if arrangements for doing so have been approved by the Administrative Agent) to the Administrative Agent of a written Borrowing Request in substantially the form of Exhibit B and signed by the Borrower.  Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

(i)            the aggregate amount of the requested Borrowing;

(ii)           the date of such Borrowing, which shall be a Business Day;

(iii)          whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

(iv)          in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period”;

(v)           the amount equal to the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base, the current total Revolving Credit Exposures (without regard to the requested Borrowing) and the pro forma total Revolving Credit Exposures (giving effect to the requested Borrowing); and

(vi)          the location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.05.

If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing.  If no Interest Period is specified with respect to any requested Eurodollar Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.  Each Borrowing Request shall constitute a representation that the amount of the requested Borrowing shall not cause the total Revolving Credit Exposures to exceed the total Commitments (i.e., the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base).

Promptly following receipt of a Borrowing Request in accordance with this Section 2.03, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

Section 2.04          Interest Elections.

(a)           Conversion and Continuance.  Each Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as specified in such Borrowing Request.  Thereafter, the Borrower may elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section 2.04.  The Borrower may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.

(b)           Interest Election Requests.  To make an election pursuant to this Section 2.04, the Borrower shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03 if the Borrower were requesting a Borrowing of the Type resulting from such election to be made on the effective date of such election.  Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy (or by electronic transmittal, if arrangements for doing so have been approved by the Administrative Agent) to the Administrative Agent of a written Interest Election Request in substantially the form of Exhibit C and signed by the Borrower.

(c)           Information in Interest Election Requests.  Each telephonic and written (including electronically transmitted) Interest Election Request shall specify the following information in compliance with Section 2.02:

(i)            the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to Section 2.04(c)(iii) and (iv) shall be specified for each resulting Borrowing);

(ii)           the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

(iii)          whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

(iv)          if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

(d)           Notice to Lenders by the Administrative Agent.  Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.

(e)           Effect of Failure to Deliver Timely Interest Election Request and Events of Default and Borrowing Base Deficiencies on Interest Election.  If the Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing.  Notwithstanding any contrary provision hereof, if an Event of Default or a Borrowing Base Deficiency has occurred and is continuing:  (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing (and any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective) and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

Section 2.05          Funding of Borrowings.

(a)           Funding by Lenders.  Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds by 1:00 p.m., Houston, Texas time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders.  The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account designated by the Borrower in the applicable Borrowing Request; provided that ABR Loans made to finance the reimbursement of an LC Disbursement as provided in Section 2.08(e) shall be remitted by the Administrative Agent to the Issuing Bank.  Except as set forth in Section 5.04, nothing herein shall be deemed to obligate any Lender to obtain the funds for its Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or will obtain the funds for its Loan in any particular place or manner.

(b)           Presumption of Funding by Lenders.  Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with Section 2.05(a) and may, in reliance upon such assumption, make available to the Borrower a corresponding amount.  In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If the Borrower and such Lender shall pay such interest to the Administrative Agent for the same or an overlapping period, the Administrative Agent shall promptly remit to the Borrower the amount of such interest paid by the Borrower for such period.  If such Lender pays its share of the applicable Borrowing to the Administrative Agent, then the amount so paid shall constitute such Lender’s Loan included in such Borrowing.  Any payment by the Borrower shall be without prejudice to any claim the Borrower may have against a Lender that shall have failed to make such payment to the Administrative Agent.

Section 2.06          Termination and Reduction of Aggregate Maximum Credit Amounts.

(a)           Scheduled Termination of Commitments.  Unless previously terminated, the Commitments shall terminate on the Maturity Date.  If at any time the Aggregate Maximum Credit Amounts or the Borrowing Base is terminated or reduced to zero, then the Commitments shall terminate on the effective date of such termination or reduction.

(b)           Optional Termination and Reduction of Aggregate Credit Amounts.

(i)            The Borrower may at any time terminate, or from time to time reduce, the Aggregate Maximum Credit Amounts; provided that (A) each reduction of the Aggregate Maximum Credit Amounts shall be in an amount that is an integral multiple of $1,000,000 and not less than $1,000,000 and (B) the Borrower shall not terminate or reduce the Aggregate Maximum Credit Amounts if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 3.04(c), the total Revolving Credit Exposures would exceed the total Commitments.

(ii)           The Borrower shall notify the Administrative Agent of any election to terminate or reduce the Aggregate Maximum Credit Amounts under Section 2.06(b)(i) at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof.  Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof.  Each notice delivered by the Borrower pursuant to this Section 2.06(b)(ii) shall be irrevocable; provided that a notice of termination of the Aggregate Maximum Credit Amounts delivered by the Borrower may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be revoked by the Borrower (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied.  Any termination or reduction of the Aggregate Maximum Credit Amounts shall be permanent and may not be reinstated.  Each reduction of the Aggregate Maximum Credit Amounts shall be made ratably among the Lenders in accordance with each Lender’s Applicable Percentage.

Section 2.07          Borrowing Base.

(a)           Borrowing Base.  As set forth in Amendment No. 9, for the period from and including the Amendment No. 9 Effective Date to but excluding the first Redetermination Date thereafter, the amount of the Borrowing Base shall be $625,000,000.  Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to Section 8.12(c) or Section 9.11(d).

(b)           Scheduled and Interim Redeterminations.  The Borrowing Base shall be redetermined semi-annually in accordance with this Section 2.07 (a “Scheduled Redetermination”), and, subject to Section 2.07(d), such redetermined Borrowing Base shall become effective and applicable to the Borrower, the Administrative Agent, the Issuing Bank and the Lenders on or about April 1 and October 1 of each year, commencing April 1, 2015.  In addition, the Borrower may, by notifying the Administrative Agent thereof, and the Administrative Agent may, at the direction of the Required Lenders, by notifying the Borrower thereof, each elect to cause the Borrowing Base to be redetermined once between each

Scheduled Redetermination (together with any redetermination described in the immediately following sentence, an “Interim Redetermination”) in accordance with this Section 2.07.  In addition to any Interim Redetermination described in the immediately preceding sentence, upon the occurrence and during the continuance of any Redetermination Event, the Administrative Agent or the Required Lenders may, by notifying the Borrower thereof, elect to cause an additional redetermination of the Borrowing Base.

(c)           Scheduled and Interim Redetermination Procedure.

(i)            Each Scheduled Redetermination and each Interim Redetermination shall be effectuated as follows:  Upon receipt by the Administrative Agent of (A) the Reserve Report and the certificate required to be delivered by the Borrower to the Administrative Agent, in the case of a Scheduled Redetermination, pursuant to Section 8.11(a) and (c), and, in the case of an Interim Redetermination, pursuant to Section 8.11(b) and (c) and (B) such other reports, data and supplemental information, including, without limitation, the information provided pursuant to Section 8.11(c), as may, from time to time, be reasonably requested by the Required Lenders (the Reserve Report, such certificate and such other reports, data and supplemental information being the “Engineering Reports”), the Administrative Agent shall evaluate the information contained in the Engineering Reports and shall, in good faith, propose a new Borrowing Base (the “Proposed Borrowing Base”) based upon such information and such other information (including, without limitation, the status of title information with respect to the Oil and Gas Properties as described in the Engineering Reports and the existence of any other Debt) as the Administrative Agent deems appropriate in its sole discretion and consistent with its normal oil and gas lending criteria as it exists at the particular time.  In no event shall the Proposed Borrowing Base exceed the Aggregate Maximum Credit Amounts.

(ii)           The Administrative Agent shall notify the Borrower and the Lenders of the Proposed Borrowing Base (the “Proposed Borrowing Base Notice”):

(A)          in the case of a Scheduled Redetermination, (1) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 8.11(a) and (c) in a timely and complete manner, then on or before the March 15th and September 15th of such year following the date of delivery or (2) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 8.11(a) and (c) in a timely and complete manner, then promptly after the Administrative Agent has received complete Engineering Reports from the Borrower and has had a reasonable opportunity to determine the Proposed Borrowing Base in accordance with Section 2.07(c)(i); and

(B)          in the case of an Interim Redetermination, promptly, and in any event, within fifteen (15) days after the Administrative Agent has received the required Engineering Reports.

(iii)          Any Proposed Borrowing Base that would increase the Borrowing Base then in effect must be approved or deemed to have been approved by all of the Lenders as

provided in this Section 2.07(c)(iii); and any Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect must be approved or be deemed to have been approved by the Required Lenders as provided in this Section 2.07(c)(iii).  Upon receipt of the Proposed Borrowing Base Notice, each Lender shall have fifteen (15) days to agree with the Proposed Borrowing Base or disagree with the Proposed Borrowing Base by proposing an alternate Borrowing Base.  If, at the end of such 15-day period, any Lender has not communicated its approval or disapproval in writing to the Administrative Agent, such silence shall be deemed to be an approval of the Proposed Borrowing Base.  If, at the end of such 15-day period, all of the Lenders, in the case of a Proposed Borrowing Base that would increase the Borrowing Base then in effect, or the Required Lenders, in the case of a Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect, have approved or deemed to have approved, as aforesaid, the Proposed Borrowing Base, then the Proposed Borrowing Base shall become the new Borrowing Base, effective on the date specified in Section 2.07(d).  If, however, at the end of such 15-day period, all of the Lenders or the Required Lenders, as applicable, have not approved or deemed to have approved, as aforesaid, the Proposed Borrowing Base, then the Administrative Agent shall poll the Lenders to ascertain the highest Borrowing Base then acceptable to all of the Lenders or the Required Lenders, as applicable, and, so long as such amount does not increase the Borrowing Base then in effect, such amount shall become the new Borrowing Base, effective on the date specified in Section 2.07(d).

(d)           Effectiveness of a Redetermined Borrowing Base.  After a redetermined Borrowing Base is approved or is deemed to have been approved by all of the Lenders or the Required Lenders, as applicable, pursuant to Section 2.07(c)(iii), the Administrative Agent shall promptly notify the Borrower and the Lenders of the amount of the redetermined Borrowing Base (the “New Borrowing Base Notice”), and such amount shall become the new Borrowing Base, effective and applicable to the Borrower, the Administrative Agent, the Issuing Bank and the Lenders:

(i)            in the case of a Scheduled Redetermination, (A) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 8.11(a) and (c) in a timely and complete manner, then on or about April 1 or October 1, as applicable, following such notice, or (B) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 8.11(a) and (c) in a timely and complete manner, then on the Business Day next succeeding delivery of such notice; and

(ii)           in the case of an Interim Redetermination, on the Business Day next succeeding delivery of such notice.

Such amount shall then become the Borrowing Base until the next Scheduled Redetermination Date, the next Interim Redetermination Date or the next adjustment to the Borrowing Base under Section 2.07(e), Section 8.12(c) or Section 9.11(d), whichever occurs first.  Notwithstanding the foregoing, no Scheduled Redetermination or Interim Redetermination shall become effective until the New Borrowing Base Notice related thereto is received by the Borrower.

(e)           Mandatory Reductions in the Borrowing Base.  In addition to the Borrowing Base redeterminations otherwise provided for in this Section 2.07, the Borrowing Base shall be automatically reduced as follows:

(i)            Effective immediately upon each Senior Unsecured Debt Incurrence, the Borrowing Base then in effect shall be automatically reduced on the date of such incurrence by an amount equal to 25% of the principal amount of such Senior Unsecured Debt Incurrence;

(ii)           With respect to any Oil and Gas Disposition, if, after giving effect thereto, the sum of the aggregate Engineered Value of the Oil and Gas Properties covered by all Oil and Gas Dispositions made since the immediately preceding Scheduled Redetermination Date (as reasonably determined by the Administrative Agent), exceeds five percent (5%) of the Borrowing Base then in effect, then the Borrowing Base shall automatically be reduced on the date such Oil and Gas Disposition is effected by an amount equal to the value, if any, assigned to the Oil and Gas Properties subject to such Oil and Gas Disposition in the then-effective Borrowing Base, as reasonably determined by the Required Lenders; and

(iii)          With respect to any Swap Event, if, after giving effect thereto, the sum of all Swap Event Reduction Amounts in respect of all Swap Events that have occurred since the immediately preceding Scheduled Redetermination Date (as reasonably determined by the Administrative Agent), exceeds five percent (5%) of the Borrowing Base then in effect, then the Borrowing Base shall automatically be reduced on the date such Swap Event is effected by an amount equal to the Swap Event Reduction Amount in respect thereof, as reasonably determined by the Required Lenders.

Section 2.08          Letters of Credit.

(a)           General.  Subject to the terms and conditions set forth herein, the Borrower may request the issuance of dollar denominated Letters of Credit for its own account in a form reasonably acceptable to the Administrative Agent and the Issuing Bank, at any time and from time to time during the Availability Period; provided that the Borrower may not request the issuance, amendment, renewal or extension of Letters of Credit hereunder if a Borrowing Base Deficiency exists at such time or would exist as a result thereof.  In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of letter of credit application or other agreement submitted by the Borrower to, or entered into by the Borrower with, the Issuing Bank relating to any Letter of Credit, the terms and conditions of this Agreement shall control.

(b)           Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions.  To request the issuance of a Letter of Credit (or the amendment, renewal or extension of an outstanding Letter of Credit), the Borrower shall hand deliver or telecopy (or transmit by electronic communication, if arrangements for doing so have been approved by the Issuing Bank) to the Issuing Bank and the Administrative Agent (not less than five (5) Business Days in advance of the requested date of issuance, amendment, renewal or extension) a notice:

(i)            requesting the issuance of a Letter of Credit or identifying the Letter of Credit to be amended, renewed or extended;

(ii)           specifying the date of issuance, amendment, renewal or extension (which shall be a Business Day);

(iii)          specifying the date on which such Letter of Credit is to expire (which shall comply with Section 2.08(c));

(iv)          specifying the amount of such Letter of Credit;

(v)           specifying the name and address of the beneficiary thereof and such other information as shall be necessary to prepare, amend, renew or extend such Letter of Credit; and

(vi)          specifying the amount of the then effective Borrowing Base and whether a Borrowing Base Deficiency exists at such time, the current total Revolving Credit Exposures (without regard to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit) and the pro forma total Revolving Credit Exposures (giving effect to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit).

Each notice shall constitute a representation that after giving effect to the requested issuance, amendment, renewal or extension, as applicable, (i) the LC Exposure shall not exceed the LC Commitment and (ii) the total Revolving Credit Exposures shall not exceed the total Commitments (i.e. the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base).

If requested by the Issuing Bank, the Borrower also shall submit a letter of credit application on the Issuing Bank’s standard form in connection with any request for a Letter of Credit.  The letter of credit application shall be amended to the extent necessary to make it consistent with the terms of this Agreement.

(c)           Expiration Date.  Each Letter of Credit shall expire at or prior to the close of business on the earlier of (i) the date one year after the date of the issuance of such Letter of Credit (or, in the case of any renewal or extension thereof, one year after such renewal or extension) and (ii) the date that is ten days prior to the Maturity Date; provided that any Letter of Credit with a one-year term may provide for the renewal thereof for additional one-year periods (which shall in no event extend beyond the date referred to in clause (ii) above).

(d)           Participations.  By the issuance of a Letter of Credit (or an amendment to a Letter of Credit increasing the amount thereof) and without any further action on the part of the Issuing Bank or the Lenders, the Issuing Bank hereby grants to each Lender, and each Lender hereby acquires from the Issuing Bank, a participation in such Letter of Credit equal to such Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of Credit.  In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of the Issuing Bank, such Lender’s Applicable Percentage of each LC Disbursement made by the Issuing Bank and not reimbursed by the Borrower on the date due as provided in Section 2.08(e), or of any

reimbursement payment required to be refunded to the Borrower for any reason.  Each Lender acknowledges and agrees that its obligation to acquire participations pursuant to this Section 2.08(d) in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or the occurrence and continuance of a Default, the existence of a Borrowing Base Deficiency or reduction or termination of the Commitments, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e)           Reimbursement.  If the Issuing Bank shall make any LC Disbursement in respect of a Letter of Credit, the Borrower shall reimburse such LC Disbursement by paying to the Administrative Agent an amount equal to such LC Disbursement not later than 12:00 noon, Houston, Texas time, on the date that such LC Disbursement is made, if the Borrower shall have received notice of such LC Disbursement prior to 10:00 a.m., Houston, Texas time, on such date, or, if such notice has not been received by the Borrower prior to such time on such date, then not later than 12:00 noon, Houston, Texas time, on (i) the Business Day that the Borrower receives such notice, if such notice is received prior to 10:00 a.m., Houston, Texas time, on the day of receipt, or (ii) the Business Day immediately following the day that the Borrower receives such notice, if such notice is not received prior to such time on the day of receipt; provided that, if the Borrower fails to so reimburse such LC Disbursement by such time, the Borrower shall, subject to the conditions to Borrowing set forth herein, be deemed to have requested, and the Borrower does hereby request under such circumstances, that such payment be financed with an ABR Borrowing in an equivalent amount and, to the extent so financed, the Borrower’s obligation to make such payment shall be discharged and replaced by the resulting ABR Borrowing.  If the Borrower fails to make such payment when due, the Administrative Agent shall notify each Lender of the applicable LC Disbursement, the payment then due from the Borrower in respect thereof and such Lender’s Applicable Percentage thereof.  Promptly following receipt of such notice, each Lender shall pay to the Administrative Agent its Applicable Percentage of the payment then due from the Borrower, in the same manner as provided in Section 2.05 with respect to Loans made by such Lender (and Section 2.05 shall apply, mutatis mutandis, to the payment obligations of the Lenders), and the Administrative Agent shall promptly pay to the Issuing Bank the amounts so received by it from the Lenders.  Promptly following receipt by the Administrative Agent of any payment from the Borrower pursuant to this Section 2.08(e), the Administrative Agent shall distribute such payment to the Issuing Bank or, to the extent that Lenders have made payments pursuant to this Section 2.08(e) to reimburse the Issuing Bank, then to such Lenders and the Issuing Bank as their interests may appear.  Any payment made by a Lender pursuant to this Section 2.08(e) to reimburse the Issuing Bank for any LC Disbursement (other than the funding of ABR Loans as contemplated above) shall not constitute a Loan and shall not relieve the Borrower of its obligation to reimburse such LC Disbursement.

(f)            Obligations Absolute.  The Borrower’s obligation to reimburse LC Disbursements as provided in Section 2.08(e) shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any Letter of Credit, any Letter of Credit Agreement or this Agreement, or any term or provision therein, (ii) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by the Issuing Bank under a Letter of Credit against presentation of a draft

or other document that does not comply with the terms of such Letter of Credit or any Letter of Credit Agreement, or (iv) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.08(f), constitute a legal or equitable discharge of, or provide a right of setoff against, the Borrower’s obligations hereunder (other than payment in full).  Neither the Administrative Agent, the Lenders nor the Issuing Bank, nor any of their Related Parties shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms or any consequence arising from causes beyond the control of the Issuing Bank; provided that the foregoing shall not be construed to excuse the Issuing Bank from liability to the Borrower to the extent of any direct damages (as opposed to consequential damages, claims in respect of which are hereby waived by the Borrower to the extent permitted by applicable law) suffered by the Borrower that are caused by the Issuing Bank’s failure to exercise care when determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof.  The parties hereto expressly agree that, in the absence of gross negligence or willful misconduct on the part of the Issuing Bank (as finally determined by a court of competent jurisdiction), the Issuing Bank shall be deemed to have exercised all requisite care in each such determination.  In furtherance of the foregoing and without limiting the generality thereof, the parties agree that, with respect to documents presented which appear on their face to be in substantial compliance with the terms of a Letter of Credit, the Issuing Bank may, in its sole discretion, either accept and make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit.

(g)           Disbursement Procedures.  The Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit.  The Issuing Bank shall promptly notify the Administrative Agent and the Borrower by telephone (confirmed by telecopy) of such demand for payment and whether the Issuing Bank has made or will make an LC Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the Borrower of its obligation to reimburse the Issuing Bank and the Lenders with respect to any such LC Disbursement.

(h)           Interim Interest.  If the Issuing Bank shall make any LC Disbursement, then, until the Borrower shall have reimbursed the Issuing Bank for such LC Disbursement (either with its own funds or a Borrowing under Section 2.08(e)), the unpaid amount thereof shall bear interest, for each day from and including the date such LC Disbursement is made to but excluding the date that the Borrower reimburses such LC Disbursement, at the rate per annum then applicable to ABR Loans.  Interest accrued pursuant to this Section 2.08(h) shall be for the account of the Issuing Bank, except that interest accrued on and after the date of payment by any Lender pursuant to Section 2.08(e) to reimburse the Issuing Bank shall be for the account of such Lender to the extent of such payment.

(i)            Replacement of the Issuing Bank.  The Issuing Bank may be replaced at any time by written agreement among the Borrower, the Administrative Agent, the replaced Issuing Bank and the successor Issuing Bank.  The Administrative Agent shall notify the Lenders of any such replacement of the Issuing Bank.  At the time any such replacement shall become effective, the Borrower shall pay all unpaid fees accrued for the account of the replaced Issuing Bank pursuant to Section 3.05(b).  From and after the effective date of any such replacement, (i) the successor Issuing Bank shall have all the rights and obligations of the Issuing Bank under this Agreement with respect to Letters of Credit to be issued thereafter and (ii) references herein to the term “Issuing Bank” shall be deemed to refer to such successor or to any previous Issuing Bank, or to such successor and all previous Issuing Banks, as the context shall require.  After the replacement of the Issuing Bank hereunder, the replaced Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of the Issuing Bank under this Agreement with respect to Letters of Credit issued by it prior to such replacement, but shall not be required to issue additional Letters of Credit.

(j)            Cash Collateralization.  If (i) any Event of Default shall occur and be continuing and the Borrower receives notice from the Administrative Agent or the Required Lenders demanding the deposit of cash collateral pursuant to this Section 2.08(j), (ii) the Borrower is required to pay to the Administrative Agent the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 3.04(c), or (iii) the Borrower is otherwise required to provide cash collateral to secure the Fronting Exposure with respect to any Defaulting Lender, then the Borrower shall deposit, in an account with the Administrative Agent, in the name of the Administrative Agent and for the benefit of the Secured Parties, an amount in cash equal to (x) in the case of an Event of Default, the LC Exposure, (y) in the case of a payment required by Section 3.04(c), the amount of such excess as provided in Section 3.04(c), and (z) in the case of a Defaulting Lender, the amount as required in Section 5.06(d), in any event, as of such date plus any accrued and unpaid interest thereon; provided that the obligation to deposit such cash collateral shall become effective immediately, and such deposit shall become immediately due and payable, without demand or other notice of any kind, upon the occurrence of any Event of Default with respect to the Borrower or any Guarantor described in Section 10.01(h) or Section 10.01(i).  The Borrower hereby grants to the Administrative Agent, for the benefit of the Issuing Bank and the Secured Parties, an exclusive first priority and continuing perfected security interest in and Lien on such account and all cash, checks, drafts, certificates and instruments, if any, from time to time deposited or held in such account, all deposits or wire transfers made thereto, any and all investments purchased with funds deposited in such account, all interest, dividends, cash, instruments, financial assets and other Property from time to time received, receivable or otherwise payable in respect of, or in exchange for, any or all of the foregoing, and all proceeds, products, accessions, rents, profits, income and benefits therefrom, and any substitutions and replacements therefor.  The Borrower’s obligation to deposit amounts pursuant to this Section 2.08(j) shall be absolute and unconditional, without regard to whether any beneficiary of any such Letter of Credit has attempted to draw down all or a portion of such amount under the terms of a Letter of Credit, and, to the fullest extent permitted by applicable law, shall not be subject to any defense or be affected by a right of set-off, counterclaim or recoupment which the Borrower or any Guarantor may now or hereafter have against any such beneficiary, the Issuing Bank, the Administrative Agent, the Lenders or any other Person for any reason whatsoever.  Such deposit shall be held as collateral securing the payment and performance of the Borrower’s or the Guarantors’ obligations under this Agreement

and the other Loan Documents.  The Administrative Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account.  Other than any interest earned on the investment of such deposits, which investments shall be made at the option and sole discretion of the Administrative Agent and at the Borrower’s risk and expense, such deposits shall not bear interest.  Interest or profits, if any, on such investments shall accumulate in such account.  Moneys in such account shall be applied by the Administrative Agent to reimburse the Issuing Bank for LC Disbursements for which it has not been reimbursed and to the extent not so applied, shall be held for the satisfaction of the reimbursement obligations of the Borrower for the LC Exposure at such time or, if the maturity of the Loans has been accelerated, be applied to satisfy other obligations of the Borrower and the Guarantors under this Agreement or the other Loan Documents.  If the Borrower is required to provide an amount of cash collateral hereunder as a result of the occurrence of an Event of Default, and the Borrower is not otherwise required to pay to the Administrative Agent the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 3.04(c), then such amount (to the extent not applied as aforesaid) shall be returned to the Borrower within three Business Days after all Events of Default have been cured or waived.

(k)           Certain Limitations.  Notwithstanding anything herein to the contrary, in addition to such other conditions and terms that are expressly provided in this Agreement, the Issuing Bank shall not be required to issue, increase, or extend any Letter of Credit hereunder (i) if such Letter of Credit is not a standby letter of credit or a letter of credit supporting the repayment of indebtedness for borrowed money of any Person, (ii) if such Letter of Credit is not governed by (A) the Uniform Customs and Practice for Documentary Credits (2007 Revision), International Chamber of Commerce Publication No. 600, or (B) the International Standby Practices (ISP98), International Chamber of Commerce Publication No. 590, in either case, including any subsequent revisions thereof approved by a Congress of the International Chamber of Commerce and adhered to by the Issuing Bank, (iii) if any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain the Issuing Bank from issuing, increasing or extending such Letter of Credit, or any Governmental Requirement applicable to the Issuing Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over the Issuing Bank shall prohibit, or request that the Issuing Bank refrain from, the issuance, increase or extension of letters of credit generally or such Letter of Credit in particular, or (iv) if any Lender is at such time a Defaulting Lender hereunder, unless the Issuing Bank has entered into reasonably satisfactory arrangements with the Borrower or such Lender to eliminate the Issuing Bank’s risk with respect to such Lender.

ARTICLE III
Payments of Principal and Interest; Prepayments; Fees

Section 3.01          Repayment of Loans.  The Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Loan on the Termination Date.

Section 3.02          Interest.

(a)           ABR Loans.  The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(b)           Eurodollar Loans.  The Loans comprising each Eurodollar Borrowing shall bear interest at the LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(c)           Post-Default Rate.  Notwithstanding the foregoing, (i) if an Event of Default under Section 10.01(a), (b), (i) or (j) has occurred and is continuing, then all outstanding Senior Secured Debt (other than interest) shall bear interest, after as well as before judgment, at a rate per annum equal to (x) in the case of principal of any Loan, two percent (2%) plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section or (y) in the case of any other amount, two percent (2%) plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section, but in no event to exceed the Highest Lawful Rate, and (ii) if any other Event of Default has occurred and is continuing and the Required Lenders so elect, then all outstanding Senior Secured Debt (other than interest) shall bear interest, after as well as before judgment, at a rate per annum equal to (x) in the case of principal of any Loan, two percent (2%) plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section or (y) in the case of any other amount, two percent (2%) plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section, but in no event to exceed the Highest Lawful Rate.

(d)           Interest Payment Dates.  Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and on the Termination Date; provided that (i) interest accrued pursuant to Section 3.02(c) shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan (other than an optional prepayment of an ABR Loan prior to the Termination Date), accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment, and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e)           Interest Rate Computations.  All interest hereunder shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day).  The applicable Alternate Base Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error, and be binding upon the parties hereto.

Section 3.03          Alternate Rate of Interest.  If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

(a)           the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the LIBO Rate for such Interest Period; or

(b)           the Administrative Agent is advised by the Required Lenders that the LIBO Rate for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (ii) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing, provided, however, that upon receipt of such notice, the Borrower may revoke any pending request for a Borrowing of, conversion to or continuation of Eurodollar Loans.

Section 3.04          Prepayments.

(a)           Optional Prepayments.  The Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part, subject to prior notice in accordance with Section 3.04(b).  Partial optional prepayments pursuant to this Section 3.04 shall be in an aggregate principal amount of $500,000 or any whole multiple of $500,000 in excess thereof.

(b)           Notice and Terms of Optional Prepayment.  The Borrower shall notify the Administrative Agent by telephone (confirmed by hand delivery or telecopy, or by electronic transmittal, if arrangements for doing so have been approved by the Administrative Agent) of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 12:00 noon, Houston, Texas time, three Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Borrowing, not later than 12:00 noon, Houston, Texas time, one Business Day before the date of prepayment.  Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of the Aggregate Maximum Credit Amounts as contemplated by Section 2.06, then such notice of prepayment may be revoked if such notice of termination is revoked in accordance with Section 2.06.  Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof.  Each partial prepayment of any Borrowing shall be in an amount that would be permitted in the case of an advance of a Borrowing of the same Type as provided in Section 2.02.  Each prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing.  Prepayments shall be accompanied by accrued interest to the extent required by Section 3.02.

(c)           Mandatory Prepayments.

(i)            If, after giving effect to any termination or reduction of the Aggregate Maximum Credit Amounts pursuant to Section 2.06(b), the total Revolving Credit Exposures exceeds the total Commitments, then the Borrower shall (A) prepay the Borrowings

on the date of such termination or reduction in an aggregate principal amount equal to such excess, and (B) if after prepaying all of the Borrowings any excess remains as a result of an LC Exposure not then covered by cash collateral as provided in Section 2.08(j), pay to the Administrative Agent on behalf of the Lenders an amount which, together with then-existing cash collateral, is necessary to fully cover such LC Exposure, to be held as cash collateral as provided in Section 2.08(j).

(ii)           Upon any redetermination of or adjustment to the amount of the Borrowing Base in accordance with Section 2.07 (other than pursuant to Section 2.07(e)) or in accordance with Section 8.12(c), if the total Revolving Credit Exposures exceeds the lesser of the Aggregate Maximum Credit Amounts and the redetermined or adjusted Borrowing Base, then the Borrower shall (A) prepay the Borrowings in an aggregate principal amount equal to such excess, and (B) if any excess remains after prepaying all of the Borrowings as a result of an LC Exposure, pay to the Administrative Agent on behalf of the Lenders an amount equal to such excess to be held as cash collateral as provided in Section 2.08(j).  The Borrower shall be obligated to make such prepayment and/or deposit of cash collateral within ninety (90) days with an amount of not less than one-half (½) of such prepayment to be paid or deposited within forty-five (45) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(d) or the date the adjustment occurs; provided that all payments required to be made pursuant to this Section 3.04(c)(ii) must be made on or prior to the Termination Date.

(iii)          Upon each reduction of the Borrowing Base pursuant to Section 2.07(e), if the total Revolving Credit Exposures exceeds the lesser of the Aggregate Maximum Credit Amounts and the Borrowing Base as reduced, then the Borrower shall, on the effective date of such reduction, (A) prepay the Borrowings in an aggregate principal amount equal to such excess, and (B) if any excess remains after prepaying all of the Borrowings as a result of an LC Exposure, pay to the Administrative Agent on behalf of the Lenders an amount equal to such excess to be held as cash collateral as provided in Section 2.08(j).

(iv)          Each prepayment of Borrowings pursuant to this Section 3.04(c) shall be applied, first, ratably to any ABR Borrowings then outstanding, and, second, to any Eurodollar Borrowings then outstanding, and if more than one Eurodollar Borrowing is then outstanding, to each such Eurodollar Borrowing in order of priority beginning with the Eurodollar Borrowing with the least number of days remaining in the Interest Period applicable thereto and ending with the Eurodollar Borrowing with the most number of days remaining in the Interest Period applicable thereto.

(v)           Each prepayment of Borrowings pursuant to this Section 3.04(c)  shall be applied ratably to the Loans included in the prepaid Borrowings.  Prepayments pursuant to this Section 3.04(c)  shall be accompanied by accrued interest to the extent required by Section 3.02.

(d)           No Premium or Penalty.  Prepayments permitted or required under this Section 3.04 shall be without premium or penalty, except as required under Section 5.02.

Section 3.05          Fees.

(a)           Commitment Fees.  The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee (the “Commitment Fee”), which shall accrue at the rate per annum equal to the Applicable Margin for Commitment Fees on the average daily amount of the unused amount of the Commitment of such Lender during the period from and including the date of this Agreement to but excluding the Termination Date.  Accrued Commitment Fees shall be payable in arrears on the last day of March, June, September and December of each year and on the Termination Date.  All Commitment Fees shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(b)           Letter of Credit Fees.  The Borrower agrees to pay (i) to the Administrative Agent for the account of each Lender a participation fee with respect to such Lender’s participations in Letters of Credit, which shall accrue at the same Applicable Margin used to determine the interest rate applicable to Eurodollar Loans on the average daily amount of such Lender’s LC Exposure (excluding any portion thereof attributable to unreimbursed LC Disbursements) during the period from and including the date of this Agreement to but excluding the later of the date on which such Lender’s Commitment terminates and the date on which such Lender ceases to have any LC Exposure, provided that in no event shall such fee be less than $750 during any year, and (ii) to the Issuing Bank a fronting fee, which shall accrue at the rate of 0.125% per annum on the average daily amount of the LC Exposure (excluding any portion thereof attributable to unreimbursed LC Disbursements) during the period from and including the date of this Agreement to but excluding the later of the date of termination of the Commitments and the date on which there ceases to be any LC Exposure.  Participation fees and fronting fees accrued through and including the last day of March, June, September and December of each year shall be payable on the third Business Day following such last day, commencing on the first such date to occur after the date of this Agreement; provided that all such fees shall be payable on the Termination Date and any such fees accruing after the Termination Date shall be payable on demand.  Any other fees payable to the Issuing Bank pursuant to this Section 3.05(b) shall be payable within 10 days after demand.  All participation fees and fronting fees shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(c)           Administrative Agent Fees.  The Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Borrower and the Administrative Agent.

ARTICLE IV
Payments; Pro Rata Treatment; Sharing of Set-offs

Section 4.01          Payments Generally; Pro Rata Treatment; Sharing of Set-offs.

(a)           Payments by the Borrower.  The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees or reimbursement of LC

Disbursements, or of amounts payable under Section 5.01, Section 5.02, Section 5.03 or otherwise) prior to 12:00 noon, Houston, Texas time, on the date when due, in immediately available funds, without defense, deduction, recoupment, set-off or counterclaim (other than deductions and withholdings required by applicable law as provided in Section 5.03(a)).  Fees, once paid, shall be fully earned and shall not be refundable under any circumstances.  Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon.  All such payments shall be made to the Administrative Agent at its offices specified in Section 12.01, except payments to be made directly to the Issuing Bank as expressly provided herein and except that payments pursuant to Section 5.01, Section 5.02, Section 5.03 and Section 12.03 shall be made directly to the Persons entitled thereto.  The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof.  If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension.  All payments hereunder shall be made in dollars.

(b)           Application of Insufficient Payments.  If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, unreimbursed LC Disbursements, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal and unreimbursed LC Disbursements then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal and unreimbursed LC Disbursements then due to such parties.

(c)           Sharing of Payments by Lenders.  If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans or participations in LC Disbursements resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and participations in LC Disbursements and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans and participations in LC Disbursements of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and participations in LC Disbursements; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this Section 4.01(c) shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans or participations in LC Disbursements to any assignee or participant, other than to the Borrower or any Affiliate thereof (as to which the provisions of this Section 4.01(c) shall apply) but not including any Affiliate that is a financial institution, insurance company, commercial bank, investment bank, or any other entity that is an “accredited investor” (as defined in Regulation D enacted by the SEC pursuant to the Securities Act of 1933,

as amended) that extends credit or buys loans as one of its businesses.  The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

Section 4.02          Presumption of Payment by the Borrower.  Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders or the Issuing Bank that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders or the Issuing Bank, as the case may be, the amount due.  In such event, if the Borrower has not in fact made such payment, then each of the Lenders or the Issuing Bank, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender or Issuing Bank with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

Section 4.03          Certain Deductions by the Administrative Agent.  If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.05(b), Section 2.08(d), Section 2.08(e) or Section 4.02 then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid.  After acceleration or maturity of the Loans, all principal will be paid ratably as provided in Section 10.02(c).

Section 4.04          Disposition of Proceeds.  The Security Instruments contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Administrative Agent for the benefit of the Secured Parties of all of the Borrower’s or Guarantors’ interest in and to production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property that constitutes Oil and Gas Properties.  The Security Instruments further provide in general for the application of such proceeds to the satisfaction of the Indebtedness and other obligations described therein and secured thereby.  Notwithstanding the assignment contained in such Security Instruments, until the occurrence of an Event of Default, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the applicable Credit Parties, and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the applicable Credit Parties.

ARTICLE V
Increased Costs; Break Funding Payments; Taxes; Illegality; Defaulting Lender

Section 5.01          Increased Costs.

(a)           Generally.  If any Change in Law shall:

(i)            impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any reserve requirement reflected in the Adjusted LIBO Rate); or

(ii)           subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b)           Capital Requirements.  If any Lender or the Issuing Bank determines that any Change in Law regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s or the Issuing Bank’s capital or on the capital of such Lender’s or the Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by the Issuing Bank, to a level below that which such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or the Issuing Bank’s policies and the policies of such Lender’s or the Issuing Bank’s holding company with respect to capital adequacy or liquidity), then from time to time the Borrower will pay to such Lender or the Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company for any such reduction suffered.

(c)           Certificates.  A certificate of a Lender or the Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or the Issuing Bank or its holding company, as the case may be, as specified in Section 5.01(a) or (b) shall be delivered to the Borrower and shall be conclusive absent manifest error.  The Borrower shall pay such Lender or the Issuing Bank, as the case may be, the amount shown as due on any such certificate within 10 days after receipt thereof.

(d)           Effect of Failure or Delay in Requesting Compensation.  Failure or delay on the part of any Lender or the Issuing Bank to demand compensation pursuant to this Section 5.01 shall not constitute a waiver of such Lender’s or the Issuing Bank’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender or the Issuing Bank pursuant to this Section 5.01 for any increased costs or reductions incurred more than 365 days prior to the date that such Lender or the Issuing Bank, as the case may be, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or the Issuing Bank’s intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 365-day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 5.02Break Funding Payments.  In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default and including any payment to a Lender as an assignment of an Eurodollar Loan on a day other than the last day of the Interest Period therefor as a result of a request by the Borrower pursuant to Section 5.04(b), (b) the conversion of any Eurodollar Loan into an ABR Loan other than on the last day of the Interest Period applicable thereto, or (c) the failure to borrow (for a reason other than the failure of a Lender to make a Loan when obligated to do so), convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event.  In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the eurodollar market.

A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section 5.02 shall be delivered to the Borrower and shall be conclusive absent manifest error.  The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

Section 5.03Taxes.

(a)Payments Free of Taxes.  Any and all payments by or on account of any obligation of the Borrower or any Guarantor under any Loan Document shall be made free and clear of and without deduction or withholding for any Taxes, except as required by applicable law; provided that if any withholding agent shall be required by applicable law (as determined in the good faith discretion of such withholding agent) to deduct or withhold any Tax from such payments, then (i) such withholding agent shall make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with applicable law, and (ii) if such Tax is an Indemnified Tax, the sum payable by the Borrower or such Guarantor, as applicable, shall be increased as necessary so that after such deduction or withholding has been made (including such deductions or withholdings for Indemnified Taxes applicable to additional sums payable under this Section 5.03(a)), the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(b)Payment of Other Taxes by the Borrower.  The Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c)Indemnification by the Borrower and Lenders.

(i)The Borrower shall indemnify each Recipient, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes payable or paid by such Recipient on or with respect to any payment by or on account of any obligation of the Borrower

hereunder (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 5.03) and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority.  A certificate of the Administrative Agent, a Lender or the Issuing Bank as to the amount of such payment or liability under this Section 5.03 shall be delivered to the Borrower and shall be conclusive absent manifest error.

(ii)Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without liming the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 12.04(c)(D) and (iii) any Excluded Taxes attributable to such Lender that are paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority.  A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error.  Each Lender authorizes the Administrative Agent to set off and apply any amounts owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to such Lender from any other source against such amount due to the Administrative Agent under this clause (c)(ii).

(d)Evidence of Payments.  As soon as practicable after any payment of Indemnified Taxes by the Borrower or a Guarantor to a Governmental Authority pursuant to this Section 5.03, the Borrower or such Guarantor shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e)Tax Forms.

(i)Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding.  In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements.  Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 5.03(e)(ii)(A) and (ii)(B) below and Section 5.03(f)) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)Without limiting the generality of the foregoing,

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding Tax;

(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(I)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed originals of IRS Form W-8BEN or IRS Form W-8BEN-E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, executed originals of IRS Form W-8BEN or IRS Form W-8BEN-E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(II)executed originals of IRS Form W-8ECI;

(III)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit I-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed originals of IRS Form W-8BEN or IRS Form W-8BEN-E; or

(IV)to the extent a Foreign Lender is not the beneficial owner, executed originals of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN or IRS Form W-8BEN-E, a U.S. Tax Compliance Certificate substantially in the form of Exhibit I-2 or Exhibit I-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit I-4 on behalf of each such direct and indirect partner;

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made.

Each Lender agrees that if any form or certification it previously delivered pursuant to Section 5.03(e) or Section 5.03(f) expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(f)FATCA.  Without limiting the generality of Section 5.03(e), if a payment made to a Lender or Issuing Bank under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender or Issuing Bank were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender or Issuing Bank (as applicable) shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender or Issuing Bank (as applicable) has complied with such Lender’s or Issuing Bank’s (as applicable) obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this paragraph (f), “FATCA” shall include any amendments made to FATCA after the Amendment No. 9 Effective Date.

(g)Treatment of Certain Refunds.  If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 5.03 (including by the payment of additional amounts pursuant to this Section 5.03), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund).  Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (g) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (g), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this paragraph (g) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the indemnification payments or additional amounts giving rise to such refund

had never been paid.  This paragraph shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(h)Administrative Agent.  On or before the date that Wells Fargo (or any successor or replacement Administrative Agent) becomes the Administrative Agent hereunder, it shall deliver to the Borrower properly completed and executed originals of either (i) IRS Form W-9, or (ii) such other documentation as will establish that the Borrower can make payments to the Administrative Agent without deduction or withholding of any Taxes imposed by the United States.  The Administrative Agent agrees that if any form or documentation it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or documentation.

(i)FATCA Grandfathering.  For purposes of determining withholding Taxes imposed under FATCA, the Borrower and the Administrative Agent shall treat (and the Lenders hereby authorize the Borrower and the Administrative Agent to treat) this Agreement and any Loan as not qualifying as a “grandfathered obligation” within the meaning of Treasury Regulation Section 1.1471-2(b)(2)(i).

(j)Defined Terms.  For purposes of this Section 5.03, the term “applicable law” includes FATCA and the term “Lender” includes the Issuing Bank.

Section 5.04Mitigation Obligations; Replacement of Lenders.

(a)Mitigation Obligations.  If any Lender requests compensation under Section 5.01, or if the Borrower is required to pay any Indemnified Tax or additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 5.03, then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 5.01 or Section 5.03, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender.  The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment

(b)Replacement of Lenders.  If (i) any Lender does not consent to any proposed increase in or reaffirmation of the Borrowing Base, (ii) any Lender is a Defaulting Lender, (iii) in connection with any consent to or approval of any proposed amendment, waiver, consent or release with respect to any Loan Document that requires the consent of each Lender or the consent of each Lender affected thereby, the consent of the Required Lenders shall have been obtained but any Lender has not so consented to or approved such proposed amendment, waiver, consent or release, (iv) in connection with any consent to or approval of any proposed amendment, waiver, consent or release with respect to any Loan Document that requires the consent of the Required Lenders, the consent of the Majority Lenders shall have been obtained but any Lender has not so consented to or approved such proposed amendment, waiver, consent or release, or (v) any Lender requests compensation under Section 5.01, or if the Borrower is

required to pay any Indemnified Tax or additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 5.03, then, in any such case, (A) the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, and (B) the Administrative Agent may as to any Defaulting Lender upon notice to such Lender and the Borrower, require that such Lender assign and delegate, without recourse (in accordance with and subject to the restrictions contained in Section 12.04), all its interests, rights and obligations under this Agreement to a permitted assignee that shall assume such obligations (which assignee may be another Lender, if such Lender accepts such assignment); provided that such Lender shall have received payment of an amount equal to the outstanding principal of its Loans and participations in LC Disbursements, accrued interest thereon, accrued fees and all other amounts payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts).  A Lender shall not be required to make any such assignment and delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.  Each Lender hereby agrees to make such assignment and delegations required under this Section 5.04.

Section 5.05Illegality.  Notwithstanding any other provision of this Agreement, in the event that it becomes unlawful for any Lender or its applicable lending office to honor its obligation to make or maintain Eurodollar Loans either generally or having a particular Interest Period hereunder, then (a) such Lender shall promptly notify the Borrower and the Administrative Agent thereof and such Lender’s obligation to make such Eurodollar Loans shall be suspended (the “Affected Loans”) until such time as such Lender may again make and maintain such Eurodollar Loans and (b) all Affected Loans which would otherwise be made by such Lender shall be made instead as ABR Loans (and, if such Lender so requests by notice to the Borrower and the Administrative Agent, all Affected Loans of such Lender then outstanding shall be automatically converted into ABR Loans on the date specified by such Lender in such notice) and, to the extent that Affected Loans are so made as (or converted into) ABR Loans, all payments of principal which would otherwise be applied to such Lender’s Affected Loans shall be applied instead to its ABR Loans.

Section 5.06Defaulting Lender.

(a)Defaulting Lender Adjustments. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as such Lender is no longer a Defaulting Lender, to the extent permitted by applicable law:

(i)Waivers and Amendments.  Such Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Majority Lenders and in the definition of Required Lenders.

(ii)Defaulting Lender Waterfall. Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of such Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article XI or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 4.01(c) shall be applied at such time or times as may be determined by the Administrative Agent as follows:

first, to the payment of any amounts owing by such Defaulting Lender to the Administrative Agent hereunder; second, to the payment on a pro rata basis of any amounts owing by such Defaulting Lender to the Issuing Bank hereunder; third, to serve as cash collateral to be held by the Administrative Agent to secure the Issuing Lender’s Fronting Exposure with respect to such Defaulting Lender in accordance with Section 2.08(j); fourth, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan hereunder in respect of which such Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; fifth, if so determined by the Administrative Agent and the Borrower, to be held in a deposit account and released pro rata in order to (x) satisfy such Defaulting Lender’s current or potential future funding obligations with respect to Loans under this Agreement and (y) serve as cash collateral to secure the Issuing Bank’s future Fronting Exposure with respect to such Defaulting Lender with respect to future Letters of Credit issued under this Agreement, in accordance with Section 2.08(j); sixth, to the payment of any amounts owing to the Lenders or the Issuing Bank as a result of any judgment of a court of competent jurisdiction obtained by any Lender or the Issuing Bank against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; seventh, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; and eighth, to such Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if (x) such payment is a payment of the principal amount of any Loans or reimbursement of LC Disbursements in respect of which such Defaulting Lender has not fully funded its appropriate share, and (y) such Loans were made or the related Letters of Credit were issued at a time when the conditions set forth in Section 6.02 were satisfied or waived, such payment shall be applied solely to pay the Loans of, and reimbursement obligations of LC Disbursements owed to, all Lenders that are not Defaulting Lenders on the applicable pro rata basis prior to being applied to the payment of any Loans of, or such Indebtedness as to Letters of Credit owed to, such Defaulting Lender until such time as all Loans and funded and unfunded participations in Letter of Credit Obligations are held by the Revolving Lenders pro rata in accordance with the Commitments without giving effect to Section 5.06(a)(iv).  Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender or to post cash collateral pursuant to this Section 5.06(a)(ii) shall be deemed paid to and redirected by such Defaulting Lender, and each Lender irrevocably consents hereto.

(iii)Certain Fees.

(I)No Defaulting Lender shall be entitled to receive any Commitment Fee for any period during which that Lender is a Defaulting Lender (and the Borrower shall not be required to pay any such fee that otherwise would have been required to have been paid to that Defaulting Lender).

(II)Each Defaulting Lender shall be entitled to receive fees under Section 3.05(b)(i) for any period during which that Lender is a Defaulting Lender only to the extent allocable to its Applicable Percentage of the stated amount of Letters of Credit for which it has provided cash collateral pursuant to Section 5.06(d).

(III)With respect to any fee under Section 3.05 not required to be paid to any Defaulting Lender pursuant to clause (A) or (B) above, the Borrower shall (x) pay to each Lender that is not a Defaulting Lender that portion of any such fee otherwise payable to such Defaulting Lender with respect to such Defaulting Lender’s participation in the LC Exposure that has been reallocated to such non-Defaulting Lender pursuant to clause (iv) below, (y) pay to the Issuing Bank the amount of any such fee otherwise payable to such Defaulting Lender to the extent allocable to the Issuing Bank’s Fronting Exposure to such Defaulting Lender, and (z) not be required to pay the remaining amount of any such fee.

(iv)Reallocation of Participations to Reduce Fronting Exposure.  All or any part of such Defaulting Lender’s participation in the LC Exposure shall be reallocated among the non-Defaulting Lenders in accordance with their respective Applicable Percentages (calculated without regard to such Defaulting Lender’s Commitment) but only to the extent that (x) the conditions set forth in Section 6.02 are satisfied at the time of such reallocation (and, unless the Borrower shall have otherwise notified the Administrative Agent at such time, the Borrower shall be deemed to have represented and warranted that such conditions are satisfied at such time), and (y) such reallocation does not cause the Revolving Credit Exposure of any non-Defaulting Lender to exceed such Lender’s Commitment.  No reallocation hereunder shall constitute a waiver or release of any claim of any party hereunder against a Defaulting Lender arising from that Lender having become a Defaulting Lender, including any claim of a non-Defaulting Lender as a result of such non-Defaulting Lender’s increased exposure following such reallocation.

(v)Cash Collateral.  If the reallocation described in clause (iv) above cannot, or can only partially, be effected, the Borrower shall, without prejudice to any right or remedy available to it hereunder or under applicable law, cash collateralize the Issuing Bank’s Fronting Exposure in accordance with the procedures set forth in Section 2.08(j).

(b)Defaulting Lender Cure.  If the Borrower, the Administrative Agent and the Issuing Bank agree in writing that a Lender is no longer a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein (which may include arrangements with respect to any cash collateral), that Lender will, to the extent applicable, purchase at par that portion of outstanding Loans of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Loans and funded and unfunded participations in Letters of Credit to be held pro rata by the Lenders in accordance with the Commitments (without giving effect to Section 5.06(a)(iv), whereupon such Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.  Notwithstanding the above, the Borrower’s and the Administrative Agent’s right to replace a Defaulting Lender pursuant to this Agreement shall be in addition to, and not in lieu of, all other rights and remedies available to the Borrower or the Administrative Agent against such Defaulting Lender under this Agreement, at law, in equity or by statute.

(c)Letters of Credit.  So long as any Lender is a Defaulting Lender, the Issuing Bank shall not be required to issue, extend, renew or increase any Letter of Credit unless it is satisfied that it will have no Fronting Exposure after giving effect thereto.

(d)Cash Collateral.  At any time that there shall exist a Defaulting Lender, within two Business Days following the written request of the Administrative Agent or the Issuing Bank (with a copy to the Administrative Agent) the Borrower shall deposit cash collateral with the Administrative Agent in an amount equal to the amount of the Issuing Bank’s Fronting Exposure with respect to such Defaulting Lender (determined after giving effect to Section 5.06(a)(iv) and any cash collateral provided by such Defaulting Lender).  If at any time the Administrative Agent determines that cash collateral is subject to any right or claim of any Person other than the Administrative Agent and the Issuing Bank as herein provided, or that the total amount of such cash collateral is less than the amount of the Issuing Bank’s Fronting Exposure with respect to such Defaulting Lender (determined after giving effect to Section 5.06(a)(iv) and any cash collateral provided by such Defaulting Lender) at such time, the Borrower will, promptly upon demand by the Administrative Agent, pay or provide to the Administrative Agent additional cash collateral in an amount sufficient to eliminate such deficiency (after giving effect to any cash collateral provided by the Defaulting Lender).

(i)Grant of Security Interest by Defaulting Lender; Agreement to Provide Cash Collateral.  To the extent cash collateral is provided by any Defaulting Lender, such Defaulting Lender hereby grants to the Administrative Agent, for the benefit of the Issuing Bank, and agrees to maintain, a first priority security interest in all such cash collateral as security for such Defaulting Lender’s obligation to fund participations in respect of Letters of Credit, to be applied pursuant to clause (ii) below.  Such Defaulting Lender shall execute any documents and agreements, including the Administrative Agent’s standard form assignment of deposit accounts, that the Administrative Agent requests in connection therewith to establish such cash collateral account and to grant the Administrative Agent a first priority security interest in such account and the funds therein.

(ii)Application.  Notwithstanding anything to the contrary contained in this Agreement, cash collateral provided under this Section 5.06(d)(i) in respect of Letters of Credit shall be applied to the satisfaction of the Defaulting Lender’s obligation to fund participations in respect of the LC Exposure (including, as to cash collateral provided by a Defaulting Lender, any interest accrued on such obligation) for which the cash collateral was so provided, prior to any other application of such property as may otherwise be provided for herein.

(iii)Termination of Requirement.  Cash collateral (or the appropriate portion thereof) provided to reduce the Issuing Bank’s Fronting Exposure shall no longer be required to be held as cash collateral pursuant to this Section 5.06(d) following (A) the elimination of the applicable Fronting Exposure (including by the termination of Defaulting Lender status of the applicable Lender), or (B) the determination by the Administrative Agent and the Issuing Bank that there exists excess cash collateral; provided that, subject to Section 5.06(a)(ii), the Person providing cash collateral and the Issuing Bank may agree that cash collateral shall be held to support future anticipated Fronting Exposure or other obligations; and provided further that to the extent that such cash collateral was provided by the Borrower, such

cash collateral shall remain subject to the security interest granted pursuant to the Loan Documents.

ARTICLE VI
Conditions Precedent

Section 6.01[Intentionally Omitted].

Section 6.02Each Credit Event.  The obligation of each Lender to make a Loan on the occasion of any Borrowing (including the initial funding), and of the Issuing Bank to issue, amend, renew or extend any Letter of Credit, is subject to the satisfaction of the following conditions:

(a)At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no Default shall have occurred and be continuing.

(b)The representations and warranties of the Borrower and the Guarantors set forth in this Agreement and in the other Loan Documents shall be true and correct in all material respects (except that such materiality qualifier shall not be applicable to any representation or warranty that already is qualified or modified by materiality in the text thereof) on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, except, in each case, to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, such representations and warranties shall continue to be true and correct as of such specified earlier date.

(c)The receipt by the Administrative Agent of a Borrowing Request in accordance with Section 2.03 or a request for a Letter of Credit in accordance with Section 2.08(b), as applicable.

Each request for a Borrowing and each request for the issuance, amendment, renewal or extension of any Letter of Credit shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in Section 6.02(a).

ARTICLE VII
Representations and Warranties

The Borrower represents and warrants to the Lenders that:

Section 7.01Organization; Powers.  The Borrower and each Guarantor is duly organized, validly existing under the laws of the jurisdiction of its organization, has all requisite power and authority, and has all material governmental licenses, authorizations, consents and approvals necessary, to own its assets and to carry on its business as now conducted, and is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where failure to have such power, authority, licenses, authorizations, consents, approvals and qualifications could not reasonably be expected to have a Material Adverse Effect.

Section 7.02Authority; Enforceability.  The Transactions are within the Borrower’s and each Guarantor’s corporate, limited liability company and/or organizational powers and have been duly authorized by all necessary organizational and, if required, action by any holders of its Equity Interests.  Each Loan Document to which the Borrower and each Guarantor is a party has been duly executed and delivered by the Borrower and such Guarantor and constitutes a legal, valid and binding obligation of the Borrower and such Guarantor, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

Section 7.03Approvals; No Conflicts.  The Transactions (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including holders of its Equity Interests or any class of directors, managers or supervisors, as applicable, whether interested or disinterested, of the Borrower or any other Person), nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of any Loan Document or the consummation of the transactions contemplated thereby, except (i) such as have been obtained, taken, given or made and are in full force and effect, (ii) recordings and filings necessary to perfect the Liens created pursuant to the Loan Documents, and (iii) filings made or to be made in the ordinary course of business, (b) will not (i) violate any Governmental Requirement or (ii) violate any Organizational Documents of the Borrower or any Guarantor or any order of any Governmental Authority, (c) will not violate or result in a default under any indenture, agreement or other instrument evidencing Material Indebtedness or any Material Farmout Agreement or Material Operating Agreement binding upon the Borrower or any Guarantor or its Properties, or give rise to a right thereunder to require any payment to be made by the Borrower or any Guarantor, and will not result in the creation or imposition of any Lien on any Property of the Borrower or any Guarantor (other than the Liens created by the Loan Documents).

Section 7.04Financial Condition; No Material Adverse Change.

(a)The Borrower has, prior to the Amendment No. 9 Effective Date, furnished to the Lenders its consolidated balance sheet and statements of income, partners’ equity and cash flows as of and for the calendar year ended December 31, 2013, certified by a Financial Officer of the Borrower.  Jones Parent has, prior to the Amendment No. 9 Effective Date, furnished to the Lenders its consolidated balance sheet and statements of income, partners’ equity and cash flows as of and for the fiscal quarter and the portion of the fiscal year ended June 30, 2014, certified by a Financial Officer of Borrower.  Such financial statements present fairly, in all material respects, the financial position and results of operations and cash flows of Borrower and Jones Parent, respectively, and their Consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year-end adjustments and the absence of footnotes in the case of the unaudited financial statements.

(b)There has been no event, development or circumstance since December 31, 2013 that has had or could reasonably be expected to have a Material Adverse Effect.

(c)As of the date of each financial statement delivered pursuant to Section 8.01(a) or Section 8.01(b), such financial statement presents fairly, in all material respects, the

financial position and results of operations and cash flows of Jones Parent and its Consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year-end adjustments and the absence of footnotes in the case of the unaudited financial statements.

Section 7.05Litigation.

(a)Except as set forth on Schedule 7.05, there are no actions, suits, investigations or proceedings by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any Guarantor (i) not fully covered by insurance (except for normal deductibles) as to which there is a reasonable possibility of an adverse determination that, if adversely determined, could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect or (ii) that involve any Loan Document or the Transactions.

(b)There has been no change in the status of the matters disclosed in Schedule 7.05 that, individually or in the aggregate, has resulted in, or materially increased the likelihood of, a Material Adverse Effect.

Section 7.06Environmental Matters.  Except for such matters as set forth on Schedule 7.06 or that, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect:

(a)the Borrower and the Guarantors and each of their respective Properties and operations thereon are, and within all applicable statute of limitation periods have been, in compliance with all applicable Environmental Laws;

(b)the Borrower and the Guarantors have obtained all Environmental Permits required for their respective operations and each of their Properties, with all such Environmental Permits being currently in full force and effect, and neither the Borrower nor any Subsidiary Guarantor has received any written notice or otherwise has knowledge that any such existing Environmental Permit will be revoked or that any application for any new Environmental Permit or renewal of any existing Environmental Permit will be protested or denied;

(c)there are no claims, demands, suits, orders, inquiries, or proceedings concerning any violation of, or any liability (including as a potentially responsible party) under, any applicable Environmental Laws that is pending or, to the Borrower’s knowledge, threatened against the Borrower or any Guarantor or any of their respective Properties or as a result of any operations at the Properties;

(d)none of the Properties contain or have contained any:  (i) underground storage tanks; (ii) asbestos-containing materials; or (iii) landfills or dumps; (iv) hazardous waste management units as defined pursuant to RCRA or any comparable state law; or (v) sites on or nominated for the National Priority List promulgated pursuant to CERCLA or any state remedial priority list promulgated or published pursuant to any comparable state law;

(e)there has been no Release or, to the Borrower’s knowledge, threatened Release, of Hazardous Materials at, on, under or from any of the Borrower’s or any Guarantor’s Properties, there are no investigations, remediations, abatements, removals, or monitorings of

Hazardous Materials required under applicable Environmental Laws at such Properties and, to the knowledge of the Borrower, none of such Properties are adversely affected by any Release or threatened Release of a Hazardous Material originating or emanating from any other real property;

(f)neither the Borrower nor any Guarantor has received written notice asserting an alleged liability or obligation under any applicable Environmental Laws with respect to the investigation, remediation, abatement, removal, or monitoring of any Hazardous Materials at, under, or Released or threatened to be Released from any real properties offsite the Borrower’s or any Guarantor’s Properties and, to the Borrower’s knowledge, there are no conditions or circumstances that would reasonably be expected to result in the receipt of such written notice;

(g)there has been no exposure of any Person or property to any Hazardous Materials as a result of or in connection with the operations and businesses of any of the Borrower’s or any Guarantor’s Properties that would reasonably be expected to form the basis for a claim for damages or compensation and, to the Borrower’s knowledge, there are no conditions or circumstances that would reasonably be expected to result in the receipt of notice regarding such exposure; and

(h)the Borrower and the Guarantors have made available to Lenders complete and correct copies of all environmental site assessment reports, investigations, studies, analyses, and correspondence on environmental matters (including matters relating to any alleged non-compliance with or liability under Environmental Laws) that are in the Borrower’s or any Guarantor’s possession or control and relating to their respective Properties or operations thereon.

Section 7.07Compliance with the Laws and Agreements; No Defaults.

(a)Each Credit Party is in compliance with all Governmental Requirements (other than Environmental Laws which are addressed in Section 7.06 above) applicable to it or its Property and all agreements and other instruments binding upon it or its Property, and possesses all licenses, permits, franchises, exemptions, approvals and other governmental authorizations necessary for the ownership of its Property and the conduct of its business, except in each case where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

(b)No Default has occurred and is continuing.

Section 7.08Investment Company Act.  No Credit Party is an “investment company” or a company “controlled” by an “investment company,” within the meaning of, and subject to regulation and registration as such under, the Investment Company Act of 1940, as amended.

Section 7.09Taxes.  Each Credit Party has timely filed or caused to be filed all Tax returns and reports required to have been filed by it and has paid or caused to be paid all Taxes required to have been paid by it, except (a) Taxes that are being contested in good faith by appropriate proceedings and for which the applicable Credit Party has set aside on its books adequate reserves in accordance with GAAP or (b) to the extent that the failure to do so could

not reasonably be expected to result in a Material Adverse Effect.  The charges, accruals and reserves on the books of the Credit Parties in respect of Taxes and other governmental charges are, in the reasonable opinion of the Borrower, adequate.  No Tax Lien has been filed and, to the knowledge of the Borrower, no claim is being asserted against any Credit Party with respect to any such Tax or other such governmental charge.

Section 7.10ERISA.  Except for such matters as could not reasonably be expected to have a Material Adverse Effect:

(a)The Borrower, its Subsidiaries and each ERISA Affiliate have complied with ERISA and, where applicable, the Code regarding each Plan.

(b)Each Plan is, and has been, established and maintained in compliance with its terms, ERISA and, where applicable, the Code.

(c)No act, omission or transaction has occurred which could result in imposition on the Borrower, any Subsidiary or any ERISA Affiliate (whether directly or indirectly) of (i) either a civil penalty assessed pursuant to subsections (c), (i), (l) or (m) of section 502 of ERISA or a tax imposed pursuant to Chapter 43 of Subtitle D of the Code or (ii) breach of fiduciary duty liability damages under section 409 of ERISA.

(d)Full payment when due has been made of all amounts which the Borrower, any Subsidiary or any ERISA Affiliate is required under the terms of each Plan or applicable law to have paid as contributions to such Plan as of the date hereof.

(e)Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains, or contributes to an employee welfare benefit plan, as defined in section 3(1) of ERISA, that may not be terminated by the Borrower, a Subsidiary or any ERISA Affiliate in its sole discretion at any time without any liability, including, without limitation, any such plan that is maintained to provide benefits to former employees of such entities (other than benefits mandated by Title I, Part 6 of ERISA and section 4980B of the Code).

(f)Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains or contributes to, or has at any time in the six-year period preceding the date hereof sponsored, maintained or contributed to, any employee pension benefit plan, as defined in section 3(2) of ERISA, that is subject to Title IV of ERISA, section 302 of ERISA or section 412 of the Code.

Section 7.11Disclosure; No Material Misstatements.  Each Credit Party has disclosed to the Administrative Agent and the Lenders all agreements, instruments and corporate or other restrictions to which it is subject, and all other matters known to it, that, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect (other than fluctuations in crude oil and natural gas prices, or changes in the oil and gas exploration and production industry or general economic conditions in the United States that, in each case, do not materially and disproportionately affect the Credit Parties).  None of the other reports, financial statements, certificates or other information furnished by or on behalf of any Credit Party to the Administrative Agent or any Lender or any of their Affiliates in connection with the negotiation of this Agreement or any other Loan Document or delivered hereunder or under any other Loan

Document (excluding Engineering Reports), as modified or supplemented by other information so furnished, contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that, with respect to projected financial information, the Borrower represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time.  There are no statements or conclusions in any Engineering Report which are based upon or include misleading information or fail to take into account material information regarding the matters reported therein, it being understood that projections concerning volumes attributable to the Oil and Gas Properties and production and cost estimates contained in each Engineering Report are necessarily based upon professional opinions, estimates and projections and that the Credit Parties do not warrant that such opinions, estimates and projections will ultimately prove to have been accurate.

Section 7.12Insurance.  Each Credit Party has (a) all insurance policies sufficient for the compliance by each of them with all material Governmental Requirements and all material agreements to which it is party and (b) insurance coverage in at least amounts and against such risk (including, without limitation, public liability) that are usually insured against by companies similarly situated and engaged in the same or a similar business for the assets and operations of the Credit Parties.  Subject to Section 8.06, the Administrative Agent has been named as an additional insured in respect of such liability insurance policies and the Administrative Agent has been named as loss payee with respect to Property loss insurance.

Section 7.13Restriction on Liens.  Except as permitted by Section 9.14, no Credit Party is a party to any material agreement or arrangement or subject to any order, judgment, writ or decree, which either restricts or purports to restrict its ability to grant Liens to the Administrative Agent and the Lenders on or in respect of its Properties to secure the Indebtedness.

Section 7.14Subsidiaries.  Except as set forth on Schedule 7.14 or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders), which shall be a supplement to Schedule 7.14, the Borrower has no Subsidiaries.

Section 7.15Location of Business and Offices.  Schedule 7.15 lists for the Borrower and each other Credit Party its full legal name, its jurisdiction of organization, its organizational identification number in its jurisdiction of organization and its principal place of business and chief executive office.  Schedule 7.15 shall be automatically supplemented by any notice delivered pursuant to Section 8.01(l) and in connection with the joinder of any Subsidiary under the Guarantee and Collateral Agreement pursuant to Section 8.13(b).

Section 7.16Properties; Titles, Etc.

(a)The Credit Parties have good and defensible title to the Oil and Gas Properties evaluated in the most recently delivered Reserve Report and good title to all their personal Properties, in each case, free and clear of all Liens except Liens permitted by Section 9.03 (subject to receipt of assignments from ExxonMobil under farmout agreements which are not more than twelve months past first production and subject to receipt of assignments from all other farmors under farmout agreements which are not more than six months past first production).  After giving full effect to the Excepted Liens, the Credit Party specified as the

owner owns the net interests in production attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such Properties shall not in any material respect obligate such Credit Party to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of the working interest of each Property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Credit Party’s net revenue interest in such Property.

(b)All material leases and agreements necessary for the conduct of the business of the Credit Parties are valid and subsisting, in full force and effect, and there exists no default or event or circumstance which with the giving of notice or the passage of time or both would give rise to a default under any such lease or leases, which could reasonably be expected to have a Material Adverse Effect.

(c)The material rights and Properties owned, leased or licensed by the Credit Parties, including, without limitation, all material easements and rights of way, include all material rights and Properties reasonably necessary for the conduct of the Credit Parties’ businesses.

(d)All of the Properties of the Credit Parties (other than the Oil and Gas Properties which are addressed in Section 7.17 below) which are reasonably necessary for the operation of their businesses are in good working condition and are maintained in accordance with prudent business standards.

(e)Each Credit Party owns, or is licensed to use, all trademarks, tradenames, copyrights, patents and other intellectual Property material to its business, and the use thereof by such Credit Party does not infringe upon the rights of any other Person, except for any such infringements that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.  The Credit Parties either own or have valid licenses or other rights to use all databases, geological data, geophysical data, engineering data, seismic data, maps, interpretations and other technical information used in their businesses as presently conducted, subject to the limitations contained in the agreements governing the use of the same, which limitations are customary for companies engaged in the business of the exploration and production of Hydrocarbons, with such exceptions as could not reasonably be expected to have a Material Adverse Effect.

Section 7.17Maintenance of Properties.  Except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and Properties unitized therewith) of the Credit Parties have been maintained, operated and developed in a good and workmanlike manner and in conformity with all Governmental Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties of the Credit Parties.  Specifically in connection with the foregoing, except for those as could not be reasonably expected to have a Material Adverse Effect, (i) no Oil and Gas Property of the Credit Parties is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (ii) 

none of the wells comprising a part of the Oil and Gas Properties (or Properties unitized therewith) of the Credit Parties are deviated from the vertical more than the maximum permitted by Governmental Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on Properties unitized therewith, such unitized Properties) of such Credit Party.  All pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and equipment owned in whole or in part by the Credit Parties that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and with respect to such of the foregoing which are operated by the Credit Parties, in a manner consistent with the Credit Parties’ past practices (other than those the failure of which to maintain in accordance with this Section 7.17 could not reasonably be expected to have a Material Adverse Effect).

Section 7.18Gas Imbalances, Prepayments.  Except as set forth on Schedule 7.18 or on the most recent certificate delivered pursuant to Section 8.11(c), on a net basis there are no gas imbalances, take or pay or other prepayments which would require the Credit Parties to deliver Hydrocarbons produced from the Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor exceeding 500,000 Mcf of gas (on an Mcf equivalent basis) in the aggregate.

Section 7.19Marketing of Production.  Except for contracts listed and in effect on the date hereof on Schedule 7.19, and thereafter either disclosed in writing to the Administrative Agent or included in the most recently delivered Reserve Report (with respect to all of which contracts the Borrower represents that the Credit Parties are receiving a price for all production sold thereunder which is computed substantially in accordance with the terms of the relevant contract and are not having deliveries curtailed substantially below the subject Property’s delivery capacity), no material agreements exist which are not cancelable on 60 days notice or less without penalty or detriment for the sale of production from the Credit Parties’ Hydrocarbons (including, without limitation, calls on or other rights to purchase, production, whether or not the same are currently being exercised) that (a) pertain to the sale of production at a fixed price and (b) have a maturity or expiry date of longer than six (6) months from the date of such disclosure or the date of such Reserve Report, as applicable.

Section 7.20Swap Agreements.  Schedule 7.20, as of the date hereof, and after the date hereof, each report required to be delivered by the Borrower pursuant to Section 8.01(d), sets forth a true and complete list of all Swap Agreements of the Credit Parties, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value thereof, all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

Section 7.21Use of Loans and Letters of Credit.  The proceeds of the Loans and the Letters of Credit shall be used to provide working capital for lease acquisitions, exploration and production operations and development drilling (including the drilling and completion of producing wells), to pay fees, commissions, expenses and transaction costs related to the foregoing and the other transactions to occur on the Effective Date, and for general corporate purposes of the Borrower and its Subsidiaries.  No Credit Party is engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate,

incidental or ultimate, of buying or carrying margin stock (within the meaning of Regulation T, U or X of the Board).  No part of the proceeds of any Loan or Letter of Credit will be used for any purpose which violates the provisions of Regulations T, U or X of the Board.

Section 7.22Solvency.  After giving effect to the transactions contemplated hereby, (a) the aggregate assets (after giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement), at a fair valuation, of the Borrower and the Guarantors, taken as a whole, will exceed the aggregate Debt of the Borrower and the Guarantors taken as a whole, as the Debt becomes absolute and matures, (b) the Borrower and the Guarantors on a consolidated basis will not have incurred or intended to incur, and will not believe that they will incur, Debt beyond their ability to pay such Debt (after taking into account the timing and amounts of cash to be received by the Borrower and the Guarantors on a consolidated basis and the amounts to be payable on or in respect of their liabilities on a consolidated basis, and giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement) as such Debt becomes absolute and matures and (c) the Borrower and the Guarantors on a consolidated basis will not have (and will have no reason to believe that they will have thereafter) unreasonably small capital for the conduct of their business.

Section 7.23OFAC; Anti-Terrorism; FCPA.

(a)Each of Jones Parent, the Borrower and their respective Subsidiaries, and, to the knowledge of the Borrower or Jones Parent, each of the foregoing’s respective joint ventures, directors, officers, employees, agents or representatives acting in any capacity, directly or indirectly, in connection with, or benefiting from, the transactions contemplated herein, is in compliance in all material respects with all applicable Sanctions Laws.

(b)None of Jones Parent, the Borrower nor any of their respective Subsidiaries nor, to the knowledge of the Borrower or Jones Parent, any joint venture, director, officers, employee, agent or representative of Jones Parent, the Borrower or any of their respective Subsidiaries, acting in any capacity, directly or indirectly, in connection with, or benefiting from, the transactions contemplated herein is a Restricted Party, or is involved in any transaction through which it is likely to become a Restricted Party.

(c)None of Jones Parent, the Borrower nor any of their respective Subsidiaries nor, to the knowledge of the Borrower or Jones Parent, any director, officer, employee, agent or representative of Jones Parent, the Borrower or any of their respective Subsidiaries, acting in any capacity, directly or indirectly, in connection with, or benefiting from, the transactions contemplated herein is aware of or has taken any action, directly or indirectly, that would result in a violation by such Persons of the Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder or any other applicable anti-corruption law.

(d)Jones Parent, the Borrower and their respective Subsidiaries have instituted and maintain policies and procedures intended to ensure continued compliance, in all material respects, with all applicable Sanctions Laws, the Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder and all other applicable anti-corruption laws.

Section 7.24Farmout Agreements.

(a)As of the date hereof and as of each date on which the certificate described in Section 8.11(c) is delivered to the Administrative Agent, Schedule 7.24, as such schedule shall be automatically supplemented to include the farmout agreements listed on the certificate delivered pursuant to Section 8.11(c), sets forth a description of each farmout agreement to which any Credit Party is a party.  With respect to each Material Farmout Agreement that is in effect on any date this representation and warranty is made or deemed made, (i) the Administrative Agent has been provided with a true and correct copy thereof as required by Section 8.11(c) to the extent the Administrative Agent has so requested a copy thereof, (ii) such Material Farmout Agreement is valid, binding and enforceable against the Credit Parties party thereto, and (iii) except as could not reasonably be expected to have a Material Adverse Effect, no default under such Material Farmout Agreement has occurred or is continuing.

(b)The Credit Parties have obtained all consents from Governmental Authorities necessary to implement and complete in all material respects the Material Farmout Agreements as in effect on the Effective Date.

(c)The Credit Parties have the right to grant a Lien on their respective interests in the Material Farmout Agreements to which they are party.

(d)The Material Farmout Agreements comply in all material respects with all applicable restrictive covenants and Governmental Requirements and with all applicable Environmental Laws.

ARTICLE VIII
Affirmative Covenants

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents shall have been paid in full (other than indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination) and all Letters of Credit shall have expired or terminated and all LC Disbursements shall have been reimbursed, the Borrower covenants and agrees with the Lenders that:

Section 8.01Financial Statements; Other Information.  The Borrower will furnish to the Administrative Agent (and the Administrative Agent shall furnish to each Lender):

(a)Annual Financial Statements.  As soon as available, but in any event in accordance with then applicable law and not later than 120 days after the end of each fiscal year of Jones Parent (or such shorter time period required by the SEC for Jones Parent to file its Form 10-K), its audited consolidated balance sheet and related statements of operations, members’ or shareholders’ equity and cash flows as of the end of and for such fiscal year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by PricewaterhouseCoopers LLP or other independent public accountants of recognized national or regional standing (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of Jones Parent and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP, consistently applied.

(b)Quarterly Financial Statements.  As soon as available, but in any event in accordance with then applicable law and not later than 60 days after the end of each fiscal quarter of each fiscal year of Jones Parent (or such shorter time period required by the SEC for Jones Parent to file its Form 10-Q), its consolidated balance sheet and related statements of operations, members’ or shareholders’ equity and cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by one of its Financial Officers as presenting fairly in all material respects the financial condition and results of operations of Jones Parent and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end adjustments and the absence of footnotes.

(c)Certificate of Financial Officer — Compliance.  Concurrently with any delivery of financial statements under Section 8.01(a) or Section 8.01(b), a certificate of a Financial Officer in substantially the form of Exhibit D hereto (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 9.01 and (iii) stating whether any change in GAAP, or in the application thereof has occurred since the date of the audited financial statements referred to in Section 7.04 and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate.

(d)Certificate of Financial Officer — Swap Agreements.  Concurrently with any delivery of financial statements under Section 8.01(a) or Section 8.01(b), a certificate of a Financial Officer, in form and substance reasonably satisfactory to the Administrative Agent, setting forth as of a recent date, a true and complete list of all Swap Agreements of the Credit Parties in effect on such date, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the then net mark-to-market value therefor, any new credit support agreements relating thereto not listed on Schedule 7.20, any margin required or supplied under any credit support document, and the counterparty to each such agreement.

(e)Certificate of Insurer — Insurance Coverage.  Concurrently with any delivery of financial statements under Section 8.01(a), a certificate of insurance coverage from each insurer with respect to the insurance required by Section 8.06, in form and substance satisfactory to the Administrative Agent, and, if requested by the Administrative Agent or any Lender, all copies of the applicable policies.

(f)Other Accounting Reports.  Promptly upon receipt thereof, a copy of each other report or letter submitted to any Credit Party by independent accountants in connection with any annual, interim or special audit made by them of the books of any such Credit Party, and a copy of any response by such Credit Party, to such letter or report.

(g)SEC and Other Filings; Reports to Shareholders.  Promptly after the same become publicly available, copies of all periodic and other reports, proxy statements and other materials filed by Jones Parent or the Borrower with the SEC, or with any national securities

exchange, or distributed by Jones Parent or the Borrower to its shareholders generally, as the case may be.

(h)Notices Under Material Instruments.  Promptly after the furnishing or receipt thereof, copies of any notices of redemption, defeasance, conversion, retirement or acquisition of, or under, any Disqualified Capital Stock, if any, of the Borrower.

(i)Lists of Purchasers.  Concurrently with the delivery of any Reserve Report to the Administrative Agent pursuant to Section 8.11, a list of all Persons purchasing Hydrocarbons from the Credit Parties.

(j)Notice of Sales of Oil and Gas Properties.  If any Credit Party intends to sell, transfer, assign or otherwise dispose of any Oil or Gas Properties (other than Hydrocarbons sold in the ordinary course of business) in accordance with Section 9.11 and such sale, transfer, assignment, or other disposition would cause an automatic reduction of the Borrowing Base pursuant to Section 2.07(e)(ii), prior written notice of such sale, transfer, assignment, or other disposition, the price thereof and the anticipated date of closing and any other details thereof reasonably requested by the Administrative Agent or any Lender.

(k)Notice of Casualty Events.  Prompt written notice, and in any event within five Business Days, of the occurrence of any Casualty Event.

(l)Information Regarding Borrower and Guarantor.  Prompt written notice (and in any event within ten (10) days prior thereto or such later date as may be reasonably acceptable to the Administrative Agent) of any change (i) in the Borrower’s or any Guarantor’s corporate name, (ii) in the location of the Borrower’s or any Guarantor’s chief executive office or principal place of business, (iii) in the Borrower’s or any Guarantor’s identity or corporate structure, (iv) in the Borrower’s or any Guarantor’s jurisdiction of organization or such Person’s organizational identification number in such jurisdiction of organization, and (v) in the Borrower’s or any Guarantor’s federal taxpayer identification number.

(m)Production Report and Lease Operating Statements.  Concurrently with the delivery of the financial statements required under Section 8.01(a) and (b) above, (i) for each calendar month during the period of three consecutive calendar months ended on such fiscal period end, the volume of production and sales attributable to production (and the prices at which such sales were made and the revenues derived from such sales) for each such calendar month from the Oil and Gas Properties of the Credit Parties, and setting forth the related ad valorem, severance and production Taxes and lease operating expenses attributable thereto and incurred for each such calendar month, and (ii) the actual volume of production from the Oil and Gas Properties of the Credit Parties for each month in such three month period, in each case, all certified by a Financial Officer as presenting fairly in all material respects the information contained therein, and to the extent applicable, all based on the actual lease operating statements for such Oil and Gas Properties.

(n)Notices of Certain Changes.  Promptly, but in any event within five (5) Business Days after the execution thereof (or such later date as the Administrative Agent may

agree), copies of any amendment, modification or supplement to any Organizational Document of the Borrower or any Guarantor.

(o)Notices Relating to Farmout Agreements.  Promptly upon their becoming available, copies of all notices of (i) any cancellation, termination, abandonment or transfer of any Material Farmout Agreement or of any material rights of the applicable Credit Party thereunder, (ii) cancellation, termination, abandonment, transfer or amendment of any farmout agreement that has been fully earned but for which the applicable Credit Party does not have record title, and (iii) any payment default or other default under any Material Farmout Agreement or any other farmout agreement that has been fully earned but for which the applicable Credit Party does not have record title.

(p)Other Requested Information.  Promptly following any request therefor, such other information regarding the operations, business affairs and financial condition of the Credit Parties (including, without limitation, any Plan and any reports or other information required to be filed with respect thereto under the Code or under ERISA), or compliance with the terms of this Agreement or any other Loan Document, as the Administrative Agent or any Lender (acting through the Administrative Agent) may reasonably request.

Any documentation or information that Borrower or Jones Parent is required to deliver to the Administrative Agent under this Section 8.01 shall be deemed to have been delivered to the Administrative Agent on the date on which such information or documentation is posted to (i) the investor relations section of www.jonesenergy.com (or any successor website thereto of which Borrower notifies the Administrative Agent in accordance with Section 12.01), (ii) the then-current website for the SEC, or (iii) www.intralinks.com (or (A) any successor website thereto of which Borrower notifies the Administrative Agent in accordance with Section 12.01 or (B) any other virtual data room website that is commonly used in the banking industry to facilitate syndicated loan transactions and to which all Lenders have been granted access).

Section 8.02Notices of Material Events.  Promptly, and in any event within five Business Days after any Responsible Officer of the Borrower obtains knowledge thereof, the Borrower will furnish to the Administrative Agent (for distribution to the Lenders) written notice of the following:

(a)the occurrence of any Default;

(b)the filing or commencement of, or the threat in writing of, any action, suit, proceeding, investigation or arbitration by or before any arbitrator or Governmental Authority against or affecting the Borrower or any Affiliate thereof not previously disclosed in writing to the Lenders or any material adverse development in any action, suit, proceeding, investigation or arbitration (whether or not previously disclosed to the Lenders) that, in either case, if adversely determined, could reasonably be expected to result in a Material Adverse Effect; and

(c)any other development that results in, or could reasonably be expected to result in, a Material Adverse Effect.

Each notice delivered under this Section 8.02 shall be accompanied by a statement of a Responsible Officer setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

Section 8.03Existence; Conduct of Business.  The Borrower and Jones Parent will, and will cause each of the Subsidiary Guarantors to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business and maintain, if necessary, its qualification to do business in each other jurisdiction in which its Oil and Gas Properties is located or the ownership of its Properties requires such qualification, except where the failure to so qualify could not reasonably be expected to have a Material Adverse Effect; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 9.10; provided further that any Subsidiary Guarantor may dissolve at any time after it has conveyed all of its Property to the Borrower or any other Subsidiary Guarantor or Jones Parent in compliance with Section 9.10.

Section 8.04Payment of Taxes.  The Borrower will, and will cause each of the Guarantors to pay or discharge all Tax liabilities of the Borrower and all of the Guarantors before the same shall become delinquent or in default, except where (i) the validity or amount thereof is being contested in good faith by appropriate proceedings, (ii) the Borrower or the Guarantors have set aside on their books adequate reserves with respect thereto in accordance with GAAP and (iii) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect or result in the seizure or levy of (A) any material Property (other than Oil and Gas Properties of the Credit Parties) of the Borrower or any Guarantor or (B) any Oil and Gas Properties of the Credit Parties which were considered in determining the then effective Borrowing Base.

Section 8.05Operation and Maintenance of Properties; Farmouts.  The Borrower, at its own expense, will, and will cause each of the Subsidiary Guarantors to:

(a)operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including, without limitation, applicable pro ration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom, except, in each case, where the failure to comply could not reasonably be expected to have a Material Adverse Effect;

(b)subject to any Disposition permitted by this Agreement, keep and maintain all Property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including, without limitation, all equipment, machinery and facilities;

(c)promptly pay and discharge, or make reasonable and customary efforts to cause to be paid and discharged, all delay rentals, royalties, and other similar payments accruing

under the leases or other agreements affecting or pertaining to its Oil and Gas Properties, except for (i) such rentals, royalties and other similar payments which are being contested in good faith by appropriate proceedings and for which reserves shall have been made therefor and (ii) such rentals, royalties and other similar payments the nonpayment of which could not reasonably be expected to result in a reduction in the Engineered Value of such Oil and Gas Properties in an amount equal to or greater than $5,000,000;

(d)promptly perform or make reasonable and customary efforts to cause to be performed, in accordance with industry standards, all material obligations required by each and all of the material assignments, deeds, leases, sub-leases, contracts and agreements affecting its interests in its Oil and Gas Properties which are reasonably necessary for the operation of their businesses and ownership of its Oil and Gas Properties; and

(e)to the extent the Borrower is not the operator of any Property, the Borrower shall use reasonable efforts to cause the operator to comply with this Section 8.05.

Section 8.06Insurance.  The Borrower will, and will cause each of the Subsidiary Guarantors to, maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations (provided, that this Section 8.06 shall not be breached if an insurance company becomes financially insolvent and the Borrower or relevant Subsidiary Guarantor reasonably promptly obtains coverage from a different, financially sound insurer) or are otherwise required to be maintained under applicable law.  The loss payable clauses or provisions in said insurance policy or policies insuring any of the collateral for the Loans shall be endorsed in favor of and made payable to the Administrative Agent as its interests may appear and such policies shall name the Administrative Agent and the Lenders as “additional insureds” and provide that the insurer will endeavor to give at least 30 days prior notice of any cancellation to the Administrative Agent.

Section 8.07Books and Records; Inspection Rights.  The Borrower and Jones Parent will, and will cause each of the Subsidiary Guarantors to, keep proper books of record and account in accordance with GAAP.  The Borrower and Jones Parent will, and will cause each of the Subsidiary Guarantors to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice and during normal business hours, to visit and inspect its Properties, to examine and make extracts from its books and records, and to discuss its affairs, finances and condition with its officers and independent accountants (provided, that so long as no Event of Default has occurred and is continuing, there may be no more than three such inspections in any calendar year).

Section 8.08Compliance with Laws.  The Borrower will, and will cause each of the Guarantors to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to them or their Property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

Section 8.09Environmental Matters.

(a)The Borrower and Jones Parent shall at its sole expense: (i) comply, and shall cause its Properties and operations and each Guarantor and each Guarantor’s Properties and operations to comply, with all applicable Environmental Laws, the breach of which could be reasonably expected to have a Material Adverse Effect; (ii) not dispose of or otherwise release, and shall cause each Subsidiary not to dispose of or otherwise release, any oil, oil and gas waste, hazardous substance, or solid waste on, under, about or from any of the Borrower’s or the Guarantors’ Properties or any other Property to the extent caused by the Borrower’s or any of the Guarantors’ operations except in compliance with applicable Environmental Laws, the disposal or release of which could reasonably be expected to have a Material Adverse Effect; (iii) timely obtain or file, and shall cause each Subsidiary to timely obtain or file, all notices, permits, licenses, exemptions, approvals, registrations or other authorizations, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of the Borrower’s or the Guarantors’ Properties, which failure to obtain or file could reasonably be expected to have a Material Adverse Effect; (iv) promptly commence and diligently prosecute to completion, and shall cause each Subsidiary to promptly commence and diligently prosecute to completion, any assessment, evaluation, investigation, monitoring, containment, cleanup, removal, repair, restoration, remediation or other remedial obligations (collectively, the “Remedial Work”) in the event any Remedial Work is required or reasonably necessary under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future disposal or other release of any oil, oil and gas waste, hazardous substance or solid waste on, under, about or from any of the Borrower’s or the Guarantors’ Properties, which failure to commence and diligently prosecute to completion could reasonably be expected to have a Material Adverse Effect; and (v) establish and implement, and shall cause each Subsidiary to establish and implement, such procedures as may be necessary to continuously determine and assure that the Borrower’s and the Guarantors’ obligations under this (a) are timely and fully satisfied, which failure to establish and implement could reasonably be expected to have a Material Adverse Effect.

(b)The Borrower will promptly, but in no event later than ten days after a Responsible Officer obtains knowledge thereof, notify the Administrative Agent and the Lenders in writing of any threatened action, investigation or inquiry by any Governmental Authority or any threatened demand or lawsuit by any landowner or other third party against the Borrower or its Properties or any Guarantor or any Guarantor’s Properties in connection with any Environmental Laws (excluding routine testing and corrective action) if (i) a Credit Party has been notified in writing of such threatened action, investigation, inquiry, demand or lawsuit and (ii) a Credit Party reasonably anticipates that such action, investigation, inquiry, demand or lawsuit will result in liability (whether individually or in the aggregate) in excess of $10,000,000, not fully covered by insurance, subject to normal deductibles.

Section 8.10Further Assurances.

(a)The Borrower at its sole expense will, and will cause the Guarantors to, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to comply with, cure any defects or accomplish the conditions precedent, covenants and agreements of the Borrower or any of the Guarantors, as the case may be, in the Loan Documents, including the Notes, or to further evidence and more fully describe the collateral intended as security for the Indebtedness,

or to correct any omissions in this Agreement or the Security Instruments, or to state more fully the obligations secured therein, or to perfect, protect or preserve any Liens created pursuant to this Agreement or any of the Security Instruments or the priority thereof, or to make any recordings, file any notices or obtain any consents, all as the Administrative Agent may reasonably deem necessary or appropriate in connection therewith.

(b)The Borrower hereby authorizes the Administrative Agent to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Property owned by any Credit Party that is subject to the Liens under the Security Instruments without the signature of the Borrower or any Guarantor where permitted by law.  A carbon, photographic or other reproduction of the Security Instruments or any financing statement covering the Mortgaged Property or any part thereof shall be sufficient as a financing statement where permitted by law.

Section 8.11Reserve Reports.

(a)On or before March 1 and September 1 of each year, commencing March 1, 2015, the Borrower shall furnish to the Administrative Agent (for distribution to the Lenders) a Reserve Report evaluating the Oil and Gas Properties of the Credit Parties as of January 1 (or December 31) or July 1 (or June 30), as applicable, of such year.  The Reserve Report to be delivered on or before March 1 of each year shall be prepared by one or more Approved Petroleum Engineers, and the Reserve Report to be delivered on or before September 1 of each year shall be prepared by or under the supervision of the chief engineer of the Borrower who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding January 1 (or December 31) Reserve Report.

(b)In the event of an Interim Redetermination, the Borrower shall furnish to the Administrative Agent (for distribution to the Lenders) a Reserve Report prepared by or under the supervision of the chief engineer of the Borrower who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding January 1 (or December 31) Reserve Report.  For any Interim Redetermination requested by the Administrative Agent or the Borrower pursuant to Section 2.07(b), the Borrower shall provide such Reserve Report with an “as of” date as required by the Administrative Agent as soon as possible, but in any event no later than thirty (30) days following the receipt of such request.

(c)With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent (for distribution to the Lenders) a certificate from a Responsible Officer certifying that, in all material respects: (i) the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct (it being understood that projections concerning volumes and production and cost estimates contained in such report are necessarily based upon professional opinions, estimates and projections upon which such Person is relying when making such certifications), (ii) the Borrower and the Subsidiary Guarantors own good and defensible title to the Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except for Liens permitted by Section 9.03 (subject to receipt of assignments from ExxonMobil under farmout agreements

which are not more than twelve months past first production and subject to receipt of assignments from all other farmors under farmout agreements which are not more than six months past first production), (iii) except as set forth on an exhibit to the certificate, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 7.18 with respect to its Oil and Gas Properties evaluated in such Reserve Report which would require the Borrower or any of the Subsidiary Guarantors to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (iv) none of their Oil and Gas Properties have been sold since the date of the last Borrowing Base determination except as set forth on an exhibit to the certificate, which certificate shall list all of such Oil and Gas Properties sold and in such detail as reasonably required by the Administrative Agent, (v) attached to the certificate is a list of all marketing agreements entered into subsequent to the later of the date hereof or the most recently delivered Reserve Report which the Borrower could reasonably be expected to have been obligated to list on Schedule 7.19 had such agreement been in effect on the date hereof, (vi) attached thereto is a schedule of the Oil and Gas Properties evaluated by such Reserve Report that are Mortgaged Properties and that the Engineered Value of such Oil and Gas Properties represents at least 80% (by value) of all Oil and Gas Properties of the Credit Parties evaluated in the Reserve Report delivered to the Administrative Agent most recently prior to the Reserve Report attached to such certificate and (vii) attached to the certificate is a list of all farmout agreements entered into subsequent to the later of the date hereof or the most recently delivered Reserve Report prior to the Reserve Report attached to such certificate. Promptly after the request of the Administrative Agent, the Borrower will deliver to the Administrative Agent true and correct copies of any Material Farmout Agreement listed on the certificate described in the immediately preceding sentence.

Section 8.12Title Information.

(a)Subject to the following sentence, within thirty (30) days of delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 8.11(a) (or such later date as may be acceptable to the Administrative Agent), the Borrower will deliver title information in form and substance reasonably acceptable to the Administrative Agent covering enough of the Oil and Gas Properties evaluated by such Reserve Report so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 80% of the Engineered Value of the Oil and Gas Properties evaluated by such Reserve Report.  Notwithstanding the foregoing, in connection with the Reserve Report delivered for the Borrowing Base redetermination effected under Amendment No. 9, within forty-five (45) days after the Amendment No. 9 Effective Date (or such later date as may be acceptable to the Administrative Agent, but in any event, not later than sixty (60) days after the Amendment No. 9 Effective Date), the Borrower will deliver title information in form and substance reasonably acceptable to the Administrative Agent covering enough of the Oil and Gas Properties evaluated by such Reserve Report so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 80% of the Engineered Value of the Oil and Gas Properties evaluated by such Reserve Report.

(b)If the Borrower has provided title information for additional Properties under Section 8.12(a), the Borrower shall, within 60 days of notice from the Administrative

Agent that title defects or exceptions exist with respect to such additional Properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not permitted by Section 9.03 raised by such information, (ii) substitute acceptable Mortgaged Properties which constitute Oil and Gas Properties and with no title defects or exceptions except for Excepted Liens (other than Excepted Liens described in clause (h) of such definition) having an equivalent value or (iii) deliver title information in form and substance acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 80% of the value of the Oil and Gas Properties evaluated by such Reserve Report.

(c)If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the 60-day period or the Borrower does not comply with the requirements to provide acceptable title information covering 80% of the value of the Oil and Gas Properties evaluated in the most recent Reserve Report, such default shall not be a Default, but instead the Administrative Agent and/or the Required Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by the Administrative Agent or the Lenders.  To the extent that the Administrative Agent or the Required Lenders are not satisfied with title to any Mortgaged Property that constitutes Oil and Gas Properties after the 60-day period has elapsed, such unacceptable Mortgaged Property shall not count towards the 80% requirement, and the Administrative Agent may send a notice to the Borrower and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Required Lenders to cause the Borrower to be in compliance with the requirement to provide acceptable title information on 80% of the value of the Oil and Gas Properties.  This new Borrowing Base shall become effective immediately after receipt of such notice.

Section 8.13Additional Collateral; Additional Guarantors.

(a)In connection with each redetermination of the Borrowing Base, the Borrower shall review the Reserve Report and the list of current Mortgaged Properties that constitute Oil and Gas Properties (as described in Section 8.11(c)(iv)) to ascertain whether such Mortgaged Properties represent at least 80% of the Engineered Value of the Oil and Gas Properties evaluated in the most recently completed Reserve Report after giving effect to exploration and production activities, acquisitions, dispositions and production.  In the event that such Mortgaged Properties do not represent at least 80% of such Engineered Value, then the Borrower shall, and shall cause the Subsidiary Guarantors to, grant, within thirty (30) days of delivery of the certificate required under Section 8.11(c). (or such later date as may be acceptable to the Administrative Agent), to the Administrative Agent as security for the Indebtedness a first-priority Lien interest (subject to Excepted Liens other than Excepted Liens described in clause (h) of such definition) on additional Oil and Gas Properties evaluated in the most recently completed Reserve Report not already subject to a Lien of the Security Instruments such that after giving effect thereto, the Mortgaged Properties that constitute Oil and Gas Properties will represent at least 80% of such Engineered Value.  All such Liens will be created and perfected by and in accordance with the provisions of deeds of trust, security agreements and financing statements or other Security Instruments, all in form and substance reasonably satisfactory to the

Administrative Agent and in sufficient executed (and acknowledged where necessary or appropriate) counterparts for recording purposes.  In order to comply with the foregoing, if any Subsidiary places a Lien on its Oil and Gas Properties and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with Section 8.13(b).

(b)The Borrower shall promptly cause each of its Domestic Subsidiaries (other than Excluded Subsidiaries) to guarantee the Indebtedness pursuant to the Guarantee and Collateral Agreement.  In connection with any such guaranty, the Borrower shall promptly, but in any event no later than 30 days after the formation or acquisition (or other similar event) of any such Subsidiary (or such later date as may be acceptable to the Administrative Agent), (i) cause such Subsidiary to execute and deliver a supplement to the Guarantee and Collateral Agreement, (ii) cause all of the Equity Interests of such Subsidiary to be pledged to the Administrative Agent, for the benefit of the Secured Parties, and to the extent such Equity Interests are certificated, cause such original stock or other certificates evidencing such Equity Interests, together with an appropriate undated stock power for each certificate duly executed in blank by the registered owner thereof, to be delivered to the Administrative Agent, and (iii) cause such Subsidiary to execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

Section 8.14ERISA Compliance.  The Borrower will promptly furnish and will cause its Subsidiaries and any ERISA Affiliate to promptly furnish to the Administrative Agent (i) promptly after the filing thereof with the United States Secretary of Labor or the Internal Revenue Service, copies of each annual and other report with respect to each Plan or any trust created thereunder or (ii) immediately upon becoming aware of the occurrence of any ERISA Event or of any material “prohibited transaction,” as described in section 406 of ERISA or in section 4975 of the Code, in connection with any Plan or any trust created thereunder, a written notice signed by the President or the principal Financial Officer, the Subsidiary or the ERISA Affiliate, as the case may be, specifying the nature thereof, what action the Borrower, the Subsidiary or the ERISA Affiliate is taking or proposes to take with respect thereto, and, when known, any action taken or proposed by the Internal Revenue Service or the Department of Labor or the PBGC with respect thereto.

Section 8.15Swap Agreements.  Prior to any Swap Event with respect to which the Swap Event Reduction Amount would exceed $5,000,000, the Borrower shall provide written notice thereof to Administrative Agent.

Section 8.16Marketing Activities.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, engage in marketing activities for any Hydrocarbons or enter into any contracts related thereto other than (i) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from their proved Oil and Gas Properties during the period of such contract, (ii) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from proved Oil and Gas Properties of third parties during the period of such contract associated with the Oil and Gas Properties of the Borrower or the Subsidiary Guarantors that the Borrower or the Subsidiary Guarantors have the right to market pursuant to joint operating agreements, unitization agreements or other similar contracts that are usual and customary in the oil and gas business and (iii) other contracts for the purchase and/or sale of Hydrocarbons of third parties (A) which have generally offsetting provisions (i.e. corresponding

pricing mechanics, delivery dates and points and volumes) such that no “position” is taken and (B) for which appropriate credit support has been taken to alleviate the material credit risks of the counterparty thereto.

Section 8.17Designation of Senior Debt.  The Borrower shall, and shall cause each Subsidiary to, designate all Indebtedness as “designated senior indebtedness” under any note or indenture documents applicable to it (including any senior unsecured notes evidencing Debt permitted under Section 9.02(h)), to the extent such note or indenture documents provide for the designation by the Borrower or such Subsidiary of other Debt as “designated senior indebtedness.”

ARTICLE IX
Negative Covenants

Until the Commitments have expired or terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents have been paid in full (other than indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination) and all Letters of Credit have expired or terminated and all LC Disbursements shall have been reimbursed, the Borrower and Jones Parent covenant and agree with the Lenders that:

Section 9.01Financial Covenants.

(a)Total Leverage Ratio.  Jones Parent will not permit the Total Leverage Ratio, as of the last day of each fiscal quarter, commencing with the fiscal quarter ended September 30, 2014 to be greater than 4.00 to 1.00.

(b)Current Ratio.  Jones Parent will not permit the ratio of (i) consolidated current assets of Jones Parent and its Consolidated Subsidiaries (including the unused amount of the total Commitments, but excluding non-cash assets under FAS 133) to (ii) consolidated current liabilities of Jones Parent and its Consolidated Subsidiaries (excluding (A) non-cash obligations under FAS 133, and (B) current maturities under this Agreement), as of the last day of each fiscal quarter, commencing with the fiscal quarter ended September 30, 2014 to be less than 1.0 to 1.0.

Section 9.02Debt.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, incur, create, assume or suffer to exist any Debt, except the following:

(a)the Notes or other Indebtedness arising under the Loan Documents or any guaranty of or suretyship arrangement for the Notes or other Indebtedness arising under the Loan Documents;

(b)Debt of the Borrower or Subsidiary Guarantor under Capital Leases and Debt incurred to finance the acquisition, construction or improvement of any fixed or capital assets other than Properties described in clauses (a) — (e) of the definition of “Oil and Gas Properties” (whether or not constituting purchase money Debt); provided, however, that the aggregate amount of all such Debt at any one time outstanding shall not exceed $12,000,000;

(c)Debt of the Borrower or Subsidiary Guarantor associated with bonds or surety obligations (i) required by Governmental Requirements in connection with the operation

of the Oil and Gas Properties or (ii) required in connection with the performance of contracts and (iii) incurred in the ordinary course of business;

(d)endorsements of negotiable instruments for collection in the ordinary course of business;

(e)intercompany Debt between the Borrower and a Subsidiary that is a Subsidiary Guarantor or between Subsidiaries that are Subsidiary Guarantors; provided that such Debt is not held, assigned, transferred, negotiated or pledged to any Person other than the Borrower or a Subsidiary Guarantor, and, provided further, that any such Debt owed by either the Borrower or a Subsidiary Guarantor shall be subordinated to the Indebtedness on terms set forth in the Guarantee and Collateral Agreement;

(f)Debt in respect of workers’ compensation claims, self-insurance obligations, bankers’ acceptance and performance and surety bonds provided by the Borrower or any Subsidiary Guarantor in the ordinary course of business;

(g)Debt of the Borrower or Subsidiary Guarantor consisting of obligations to pay insurance premiums;

(h)unsecured Debt of the Borrower or any Subsidiary Guarantor evidenced by bonds, debentures, notes or other similar instruments (including any Permitted Refinancing Debt in respect thereof); provided that, (i) the scheduled maturity date of such Debt shall not be earlier than one year after the Maturity Date, (ii) such Debt shall not have any amortization or other requirement to purchase, redeem, retire, defease or otherwise make any payment in respect thereof, other than at scheduled maturity thereof and mandatory prepayments or puts triggered upon change in control, sale of all or substantially all assets and certain asset sales, in each case which are customary with respect to such type of Debt, (iii) the aggregate principal amount of such Debt shall not exceed $900,000,000, and (iv) the agreements and instruments governing such Debt shall not contain (A) any financial maintenance covenants that are more restrictive than those in this Agreement or any other affirmative or negative covenants that are, taken as a whole, materially more restrictive than those set forth in this Agreement; provided that the inclusion of any covenant that is customary with respect to such type of Debt and that is not found in this Agreement shall not be deemed to be more restrictive for purposes of this clause (A), (B) any restriction on the ability of the Borrower or any of its Subsidiaries to amend, modify, restate or otherwise supplement this Agreement or the other Loan Documents (other than as to the maximum principal amount of Debt to be incurred hereunder), (C) any restrictions on the ability of any Subsidiary of the Borrower to guarantee the Indebtedness to the extent the Indebtedness is permitted thereunder, provided that a requirement that any such Subsidiary also guarantee such Debt shall not be deemed to be a violation of this clause (C), or (D) any restrictions on the ability of any Subsidiary or the Borrower to pledge assets as collateral security for the Indebtedness to the extent the Indebtedness is permitted thereunder; and

(i)other Debt of the Borrower or Subsidiary Guarantor in an aggregate principal amount not to exceed $30,000,000 at any one time outstanding.

For the avoidance of doubt, when calculating the amount of Debt for purposes of determining compliance with clause (b), (h) or (i) above, such calculation shall not include any guarantee by a Credit Party in respect of other Debt already included in such calculation.

Section 9.03Liens.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, create, incur, assume or permit to exist any Lien on any of its Properties (now owned or hereafter acquired), except:

(a)Liens securing the payment of any Indebtedness created pursuant to the Security Instruments;

(b)Excepted Liens;

(c)Liens securing Debt permitted under Section 9.02(b); provided that such Liens do not at any time encumber any property other than the property financed by such Debt;

(d)Liens arising from UCC financing statements filed on a precautionary basis in respect of operating leases intended by the parties to be true leases (other than any such leases entered into in violation of this Agreement);

(e)Liens on insurance proceeds securing Debt permitted by Section 9.02(g) of this Agreement; and

(f)Liens on Property not constituting collateral for the Indebtedness and not otherwise permitted by the foregoing clauses of this Section 9.03; provided that the aggregate principal or face amount of all Debt and other obligations permitted to be secured under this clause (f) shall not exceed $6,000,000 at any time outstanding.

Section 9.04Dividends, Distributions and Redemptions.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment to its Equity Interest holders without the prior approval of the Majority Lenders, except that: (a) the Borrower and each Subsidiary Guarantor may declare and pay dividends or distributions with respect to their Equity Interests payable solely in additional Equity Interests of such Person (other than Disqualified Capital Stock), (b) each Subsidiary may make Restricted Payments to the Borrower and to any Subsidiaries of the Borrower that are Subsidiary Guarantors, (c)(i) from and after the Amendment No. 8 Effective Date until March 31, 2015, the Borrower or such Subsidiary Guarantor may make cash Restricted Payments in an aggregate amount not to exceed $10,000,000 in respect of repurchases of its Equity Interests from employees (and their heirs, estates and assigns) or from Jones Parent in order for Jones Parent to repurchase its Equity Interests from employees (and their heirs, estates and assigns), and (ii) from and after April 1, 2015, the Borrower or such Subsidiary Guarantor may make cash Restricted Payments in respect of repurchases of its Equity Interests from employees (and their heirs, estates and assigns) or from Jones Parent in order for Jones Parent to repurchase its Equity Interests from employees (and their heirs, estates and assigns), in any case under this clause (ii), upon the death, termination or disability of such employee in an aggregate amount under this clause (ii) not to exceed an amount equal to (A) $5,000,000 minus (B) the aggregate amount of cash Restricted Payments made in accordance with sub-clause (c)(i), and, in any event, such amount shall be no less than $0, (d) the Borrower may make Permitted

Tax Distributions, (e) the Borrower may make Permitted Payments in an aggregate amount not to exceed $5,000,000 in any fiscal year, and (f) Borrower may declare and pay cash dividends or distributions to Jones Parent in an aggregate amount not to exceed $5,000,000 in any fiscal year, so long as after giving effect to such payment, (i) Liquidity is greater than or equal to 10% of the Borrowing Base then in effect and (ii) the Total Leverage Ratio, after giving pro forma effect to such Restricted Payment, is not greater than 3.50 to 1.00.

Section 9.05Investments, Loans and Advances.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, make or permit to remain outstanding any Investments in or to any Person, except that the foregoing restriction shall not apply to:

(a)Investments reflected in the Financial Statements or which are disclosed to the Lenders in Schedule 9.05;

(b)Investments made by the Borrower or any Subsidiary Guarantor in the form of accounts receivable arising in the ordinary course of business;

(c)Investments made by the Borrower or any Subsidiary Guarantor in the form of direct obligations of the United States or any agency thereof, or obligations guaranteed by the United States or any agency thereof, in each case maturing within one year from the date of creation thereof;

(d)Investments made by the Borrower or any Subsidiary Guarantor in the form of commercial paper maturing within one year from the date of creation thereof rated in the highest grade by S&P or Moody’s;

(e)Investments made by the Borrower or any Subsidiary Guarantor in the form of deposits maturing within one year from the date of creation thereof, including certificates of deposit issued by, any Lender or any office located in the United States of any other bank or trust company which is organized under the laws of the United States or any state thereof, has capital, surplus and undivided profits aggregating at least $100,000,000 (as of the date of such bank or trust company’s most recent financial reports) and has a short term deposit rating of no lower than A2 or P2, as such rating is set forth from time to time, by S&P or Moody’s, respectively; provided that First National Bank of Albany/Breckenridge shall not be subject to the deposit rating requirement;

(f)Investments made by the Borrower or any Subsidiary Guarantor in the form of deposits in money market funds investing exclusively in Investments described in Section 9.05(c), Section 9.05(d) or Section 9.05(e);

(g)Investments in or to (or, with respect to Guarantees permitted under Section 9.02, for the benefit of) any other Credit Party;

(h)Investments in the form of direct ownership interests in additional Oil and Gas Properties and gas gathering systems related thereto or related to farm-out, farm-in, joint operating, joint venture or area of mutual interest agreements, gathering systems, pipelines or other similar arrangements which are usual and customary in the oil and gas exploration and production business located within the geographic boundaries of the United States of America;

(i)Investments in the form of loans or advances to employees, officers, directors or managers of the Borrower, as the case may be, to the extent that such Investment is permitted by applicable law, including (to the extent applicable) Section 402 of the Sarbanes Oxley Act of 2002; provided that the aggregate outstanding amount of Investments under this Section 9.05(i) shall not exceed $1,000,000 in the aggregate at any time;

(j)Investments in the form of in stock, obligations or securities received in settlement of debts arising from Investments permitted under this Section 9.05 owing to the Borrower or any of the Subsidiary Guarantors as a result of a bankruptcy or other insolvency proceeding of the obligor in respect of such debts or upon the enforcement of any Lien in favor of the Borrower or any of the Subsidiary Guarantors; provided that the Borrower shall give the Administrative Agent prompt written notice in the event that the aggregate amount of all Investments held at any one time under this Section 9.05(j) exceeds $500,000;

(k)Investments in the form of Debt permitted under Section 9.02(e);

(l)Investments in the form of Swap Agreements to the extent permitted under Section 9.16;

(m)Investments in connection with the purchase, lease or other acquisition of tangible assets of any Person, and investments made by such Persons in connection with the purchase, lease or other acquisition of all or substantially all of the business of any other Person, or all of the Equity Interests of any other Person, or any division, line of business or business unit of any other Person (including by the merger or consolidation of such Person into the Borrower or any Subsidiary Guarantor); provided that (i) any newly acquired Subsidiary shall promptly comply with the requirements of Section 8.13(b), (ii) no Default exists before and after giving effect to such Investment, (iii) immediately after giving effect to such Investment, Availability is greater than or equal to the greater of (A) $12,000,000 and (B) 5% of the lesser of the Aggregate Maximum Credit Amounts and the Borrowing Base then in effect, and (iv) after giving effect to such Investment, the Borrower shall be in pro forma compliance with Section 9.01;

(n)Investments permitted by Section 9.10 or Section 9.13;

(o)Investments by the Borrower or a Subsidiary Guarantor in the Equity Interests of its Subsidiaries as of the date of this Agreement;

(p)Investments by a Credit Party in CPD SPE required under the CPDA; and

(q)other Investments made by the Borrower or any Subsidiary Guarantor not to exceed $35,000,000 in the aggregate at any time.

Section 9.06Nature of Business; International Operations.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, allow any material change to be made in the character of their business as an independent oil and gas exploration and production company.  From and after the date hereof, the Borrower and the Subsidiary Guarantors will not acquire or make any other expenditure (whether such expenditure is capital, operating or otherwise) in or related to, any Oil and Gas Properties not located within the geographical boundaries of the United States.

Section 9.07Proceeds of Loans.  The Borrower will not permit the proceeds of the Loans to be used for any purpose other than those permitted by Section 7.21.  Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause any of the Loan Documents to violate Regulations T, U or X or any other regulation of the Board or to violate Section 7 of the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in effect.  If requested by the Administrative Agent, the Borrower will furnish to the Administrative Agent and each Lender a statement to the foregoing effect in conformity with the requirements of FR Form U-1 or such other form referred to in Regulation U, Regulation T or Regulation X of the Board, as the case may be.

Section 9.08ERISA Compliance.  Except for such matters which, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect, the Borrower will not, and will not permit any of the Subsidiary Guarantors to, at any time:

(a)engage in, or permit any ERISA Affiliate to engage in, any transaction in connection with which the Borrower, a Subsidiary or any ERISA Affiliate could be subjected to either a civil penalty assessed pursuant to subsections (c), (i), (l) or (m) of section 502 of ERISA or a tax imposed by Chapter 43 of Subtitle D of the Code.

(b)fail to make, or permit any ERISA Affiliate to fail to make, full payment when due of all amounts which, under the provisions of any Plan, agreement relating thereto or applicable law, the Borrower, a Subsidiary or any ERISA Affiliate is required to pay as contributions thereto.

(c)contribute to or assume an obligation to contribute to, or permit any ERISA Affiliate to contribute to or assume an obligation to contribute to (i) any employee welfare benefit plan, as defined in section 3(1) of ERISA, which may not be terminated by such entities in their sole discretion at any time without any material liability, including, without limitation, any such plan that is maintained to provide benefits to former employees of such entities, (other than benefits mandated by Title I, Part 6 of ERISA and section 4980B of the Code), or (ii) any employee pension benefit plan, as defined in section 3(2) of ERISA, that is subject to Title IV of ERISA, section 302 of ERISA or section 412 of the Code.

Section 9.09Sale or Discount of Receivables.  Except for (a) receivables obtained by the Borrower or any of the Subsidiary Guarantors out of the ordinary course of business, (b) the settlement of joint interest billing accounts in the ordinary course of business, (c) discounts granted to settle collection of accounts receivable, (d) the sale of defaulted accounts arising in the ordinary course of business in connection with the compromise or collection thereof and not in connection with any financing transaction, and (e) the Alpine Releases, the Borrower will not, and will not permit any of the Subsidiary Guarantors to, discount or sell (with or without recourse) any of its notes receivable or accounts receivable.

Section 9.10Mergers, Etc.  Neither the Borrower nor any of the Guarantors will merge into or with or consolidate with any other Person, or sell, lease or otherwise dispose of (whether in one transaction or in a series of related transactions) all or substantially all of its Property to any other Person, except that (a) any Guarantor may merge into or with or consolidate with the

Borrower in a transaction in which the Borrower is the surviving entity, (b) any Guarantor may merge into or with or consolidate with any other Guarantor, (c) any Guarantor may dispose of all or substantially all of its Property to the Borrower or any other Guarantor, and (d) the Borrower or any Subsidiary Guarantor may engage in any acquisition to the extent permitted under Section 9.05.

Section 9.11Sale of Properties.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, sell, assign, farm-out, convey or otherwise transfer (each, a “Disposition”) any Property except for:

(a)the sale of Hydrocarbons and seismic data (other than such data pertaining to proved Oil and Gas Properties evaluated in the most recent Reserve Report) in the ordinary course of business;

(b)Dispositions of undeveloped acreage, including undeveloped acreage of the Credit Parties under any farmout agreements not included in the most recent Reserve Report, and assignments in connection with such farmouts and transfers;

(c)the sale or transfer or abandonment of obsolete, worn-out or surplus equipment that is no longer necessary for the business of the Borrower or such Subsidiary Guarantor or is replaced by equipment of at least comparable value and use;

(d)the Disposition of any Oil and Gas Property or any interest therein or any Subsidiary owning Oil and Gas Properties; provided that (i) in the case of any such Disposition other than a Specified Disposition (as defined below), at least 75% of the consideration received in respect of such Disposition shall be cash (it being understood that for purposes of calculating such 75% for purposes of this clause (i) only, any securities, notes or other consideration received by the Borrower or any Subsidiary Guarantor in respect of such Disposition that could reasonably be expected to be converted into cash within 90 days after such Disposition and which are, within such 90 day period, converted by the Borrower or such Subsidiary Guarantor into cash shall be deemed to be cash for purposes of this clause (i) to the extent of the cash received in such conversion); (ii) in the case of any Specified Disposition, the cash consideration received in respect of such Disposition shall be at least equal to the greater of (A) 75% of the total consideration received in respect of such Disposition and (B) the value attributed to the Oil and Gas Properties subject to such Specified Disposition, if any, in the then effective Borrowing Base; (iii) the consideration received in respect of such Disposition shall be equal to or greater than the fair market value of the Oil and Gas Property, interest therein or Subsidiary subject of such Disposition (as reasonably determined by the Borrower and, if requested by the Administrative Agent, the Borrower shall deliver a certificate of a Responsible Officer certifying to that effect), (iv) the Borrowing Base shall be reduced to the extent required under Section 2.07(e)(ii) (any such Disposition for which there is such a Borrowing Base reduction being referred to herein as a “Specified Disposition”), and (v) if any such Disposition is of a Subsidiary owning Oil and Gas Properties, such Disposition shall include all the Equity Interests of such Subsidiary;

(e)Dispositions of Property by any Credit Party to any other Credit Party;

(f)Dispositions to the extent permitted by Sections 9.03, 9.04, 9.05 and 9.10;

(g)Asset Swaps;

(h)use of cash and cash equivalents for transactions not expressly prohibited hereunder;

(i)Dispositions consisting of the licensing or sublicensing of intellectual property and licenses, leases or subleases of other Property (other than Oil and Gas Properties);

(j)cancellations of intercompany Debt between or among Credit Parties;

(k)Dispositions of Property required under the CPDA; and

(l)Disposition of Property not otherwise permitted in the preceding clauses of this Section 9.11); provided that, (i) such Disposition is not of any Property described in clauses (a) — (e) of the definition of “Oil and Gas Properties” in Section 1.02 of this Agreement, and (ii) the fair market value of all Property disposed of pursuant to this Section 9.11(l) shall not exceed $23,000,000.

Section 9.12Transactions with Affiliates.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of Property or the rendering of any service, with any Affiliate unless such transactions are otherwise permitted under this Agreement and are upon fair and reasonable terms no less favorable to it than it would obtain in a comparable arm’s length transaction with a Person not an Affiliate; provided that this Section shall not apply to: (a) transactions among the Credit Parties; (b) transactions among one or more Credit Parties and CPD SPE pursuant to the CPDA; (c) any Restricted Payment to the extent permitted by Section 9.04; (d) with respect to any Person serving as an officer, director, employee or consultant of the Borrower or any Subsidiary Guarantor (i) the payment of reasonable compensation, benefits or indemnification liabilities in connection with his or her services in such capacity, (ii) the making of advances for travel or other business expenses in the ordinary course of business or (iii) such Person’s participation in any benefit or compensation plan; (e) Investments to the extent permitted under Section 9.05(i), (k), (o) or (p), and Investments to the extent permitted by Section 9.13; and (f) the payment of Acquisition Related Costs.

Section 9.13Subsidiaries.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, create or acquire any additional Subsidiaries, unless the Borrower promptly, but, in any event, no later than 30 days after such formation or acquisition of any such Subsidiary (or such later date as may be acceptable to the Administrative Agent), gives written notice to the Administrative Agent of such creation or acquisition and complies with Section 8.13(b).  The Borrower shall have no Foreign Subsidiaries, unless permitted by the Administrative Agent.  The Borrower shall not have any Subsidiary other than Subsidiaries all of the Equity Interests of which are owned, directly or indirectly, by the Borrower.

Section 9.14Negative Pledge Agreements; Dividend Restrictions.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, incur, assume or suffer to exist any contract, agreement or understanding (other than this Agreement or the Security Instruments)

which in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Property in favor of the Administrative Agent and the Lenders or restricts any Subsidiary from paying dividends or making distributions to the Borrower or any Subsidiary Guarantor, or which requires the consent of or notice to other Persons in connection therewith; provided, that the foregoing shall not prevent (a) restrictions on the transfer of Equity Interests in joint ventures, (b) customary non-assignment provisions in leases, licenses, permits and other agreements entered into in the ordinary course of business, (c) in connection with any Disposition of Property permitted hereunder, any restriction with respect to such Property imposed under the agreement or agreements governing such Disposition, (d) restrictions imposed by any Governmental Authority or under any Governmental Requirement, (e) any restriction imposed on the granting, conveying, creation or imposition of any Lien on any Property of a Credit Party imposed by any contract, agreement or understanding related to the Liens permitted under clause (c), (e) or (f) of Section 9.03 so long as such restriction only applies to the Property permitted under such clauses to be encumbered by such Liens, (f) Lien restrictions imposed by any contract, agreement or understanding related to Debt permitted under Section 9.02(h) to the extent relating to the amount of Indebtedness permitted to be secured by Liens thereunder, and (g) any provision contained in any contract, agreement or understanding related to Debt permitted under Section 9.02(h) specifying that dividends or distributions paid by any Subsidiary to holders of its Equity Interests shall be paid on a pro rata basis.

Section 9.15Gas Imbalances, Take-or-Pay or Other Prepayments.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, allow gas imbalances, take-or-pay or other prepayments with respect to the Oil and Gas Properties of the Borrower or any of the Subsidiary Guarantors that would require the Borrower or any of the Subsidiary Guarantors to deliver Hydrocarbons at some future time without then or thereafter receiving full payment therefor to exceed 500,000 Mcf of gas (on an Mcf equivalent basis) in the aggregate.

Section 9.16Swap Agreements.

(a)Commodity Swap Agreements.

(i)Incurrence.  Subject to the additional limitation in Section 9.16(a)(ii)(B) below, the Borrower will not, and will not permit any of the Subsidiary Guarantors to, enter into any Swap Agreement in respect of commodities other than such Swap Agreements entered into with Approved Counterparties and not for speculative purposes and with a duration no longer than five years from the date the applicable Swap Agreement is entered into; provided that, the Hedged Volume in any month, determined at the time such Swap Agreement is entered into and after giving effect thereto (the “Measurement Date”), shall not exceed for each month during the period during which such Swap Agreement is in effect, the greater of (A) 100% of the anticipated projected production from proved, developed, producing Oil and Gas Properties set forth in the most recently delivered Reserve Report (subject to the following sentence), and (B) volumes set forth in the grid below for the applicable period as determined (subject to the following sentence) by reference to the Reserve Report most recently delivered to the Administrative Agent:

Volumes Covered by Swap Agreements	Applicable Period Covered By Swap Agreements
85% of the anticipated projected production from proved Oil and Gas Properties	First 24 months after the Measurement Date
75% of the anticipated projected production from proved Oil and Gas Properties	Months 25 — 60 after the Measurement Date

For purposes of entering into or maintaining Swap Agreement trades or transactions under this Section 9.16(a)(i), forecasts of reasonably anticipated production from the Borrower’s and its Subsidiaries’ proved Oil and Gas Properties as set forth on the most recent Reserve Report delivered pursuant to the terms of this Agreement shall be revised to account for any increase or decrease therein anticipated because of information obtained by the Borrower or any of its Subsidiaries subsequent to the publication of such Reserve Report including the Borrower’s or any of its Subsidiaries’ internal forecasts of production decline rates for existing wells and additions to or deletions from anticipated future production from new wells and completed acquisitions coming on stream or failing to come on stream.

(ii)Maintenance.  If, after the end of any calendar month, commencing with the calendar month ending October 31, 2014, the Borrower determines that the Hedged Volume for such calendar month exceeded the Actual Production Volume for such month, then (A) the Borrower shall (1) promptly notify the Administrative Agent (but in any event within 21 days of such month end), and (2) if requested by the Administrative Agent, within 30 days after such request, effect (or cause the applicable Subsidiary Guarantor to effect) such Swap Terminations to the extent necessary to cause the Hedged Volume not to exceed 100% of reasonably anticipated projected production from Oil and Gas Properties of the Borrower and its Subsidiaries for the succeeding calendar months; and (B) as to any particular commodity (including substitutes therefor as provided in the penultimate sentence of this Section 9.16(a)) which is over-hedged for any calendar month, the Borrower will not, and will not permit any of the Subsidiary Guarantors to, enter into any Swap Agreement in respect of such commodity until the Borrower is in compliance with each of the requirements in the immediately preceding clause (A) or the Administrative Agent otherwise consents.

The requirements in clauses (i) and (ii) of this Section 9.16(a) (x) shall be determined with volumes of oil, volumes of gas and volumes of natural gas liquids calculated separately and (y) shall not apply to basis differential swaps on volumes already hedged pursuant to other Swap Agreements or to put options and price floors (including floors embedded in participating swaps or other similar transactions to the extent not offset by calls) for Hydrocarbons with respect to which the Borrower or any Subsidiary Guarantor is the buyer of such put options or price floors.  Furthermore, so long as the Borrower and the Subsidiary Guarantors properly identify and consistently report such Swap Agreements in the production reports required under Section 8.01(m), the Borrower may utilize Swap Agreements covering crude oil as a substitute for hedging natural gas liquids on an Economic BOE (as defined below) basis; provided that, (A) in determining compliance with Section 9.16(a)(i) above, the Borrower shall use the Economic BOE in effect at the time the Swap Agreement is entered into and (B) in determining compliance with Section 9.16(a)(ii) above, the Borrower shall use the Economic BOE in effect at the time of calculation (and not at the time the applicable Swap Agreement was entered into).  “Economic BOE” means the volume of crude oil (measured in barrels) of the Borrower’s and Subsidiary Guarantors’ production that has the equivalent value (in dollars) to one barrel of natural gas liquids of the Borrower’s and Subsidiary Guarantors’ production as determined on a trailing twelve month basis.

(b)Interest Swap Agreements.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to, enter into any Swap Agreement in respect of interest rates

other than such Swap Agreements (i) with an Approved Counterparty, (ii) with a duration that does not extend beyond the Maturity Date and (iii) which effectively convert interest rates from floating to fixed, the notional amounts of which (when aggregated with all other Swap Agreements of the Borrower and the Subsidiary Guarantors then in effect effectively converting interest rates from floating to fixed) do not exceed 75% of the then outstanding principal amount of the Borrower’s Debt for borrowed money which bears interest at a floating rate, using the same index used to determine floating rates of interest on the indebtedness to be hedged.

(c)Limitations.  Notwithstanding anything herein to the contrary, in no event shall any Swap Agreement contain any requirement, agreement or covenant for the Borrower or any of the Subsidiary Guarantors to post collateral (including a letter of credit) or margin to secure their obligations under such Swap Agreement or to cover market exposures; provided that, this clause (c) shall not prevent a Hedge Bank from requiring the obligations under its Swap Agreement with any Credit Party to be secured by the Liens granted to the Administrative Agent under the Security Instruments pursuant to such Security Instruments.

(d)Acquisition Swap Agreements.

(i)Notwithstanding anything in Section 9.16(a) to the contrary but subject to clause (iii) below, the Borrower and each Subsidiary Guarantor may enter into commodity Swap Agreements with an Approved Counterparty having notional volumes in excess of the amounts set forth in Section 9.16(a)(i) (such Swap Agreements being “Acquisition Swap Agreements”) in anticipation of the acquisition of Oil and Gas Properties in a transaction not prohibited by this Agreement (any such Oil and Gas Properties being referred to herein as the “Target Oil and Gas Properties” and any such acquisition being referred to herein as a “Subject Acquisition”) if (x) the Borrower or such Subsidiary Guarantor, as applicable, has entered into a definitive purchase and sale agreement for such Target Oil and Gas Properties, (y) the tenor of any such Acquisition Swap Agreement does not exceed a period of beginning on the expected closing date of such Subject Acquisition equal to the remainder of the calendar year in which such Acquisition Swap Agreements are entered into plus the next 5 calendar years and (z) the aggregate notional volume of commodities covered under all of the Acquisition Swap Agreements with respect to any Subject Acquisition in any month, determined on the Measurement Date with respect thereto, shall not exceed for each month during the period during which such Acquisition Swap Agreement is in effect, the greater of (A) 100% of the Projected Target Property PDP Volumes and (B) the volumes set forth in the grid below for the applicable period as determined by the Borrower’s internal engineers as proved reserves:

Volumes Covered by Acquisition Swap Agreements	Applicable Period Covered by Acquisition Swap Agreements
85% of the anticipated projected production from proved Target Oil and Gas Properties	First 24 months after acquisition of Target Oil and Gas Properties
75% of the anticipated projected production from proved Target Oil and Gas Properties	Months 25 — 60 after acquisition of Target Oil and Gas Properties

The requirements in this clause (i) shall (x) be determined with volumes of oil, volumes of gas and volumes of natural gas liquids calculated separately and (y) not apply to basis differential swaps on volumes already hedged pursuant to other Acquisition Swap Agreements or to put options and price floors (including floors embedded in participating swaps or other similar transactions to the extent not offset by calls) for Hydrocarbons with respect to which the Borrower or any Subsidiary Guarantor is the buyer of such put options or price floors.

(ii)Subject to the terms of clause (iii) below, with respect to Target Oil and Gas Properties, (x) the aggregate notional volume of commodities covered under all Acquisition Swap Agreements with respect to such Target Oil and Gas Properties shall not be included in any determination of “Hedged Volume” for purposes of determining compliance with Section 9.16(a) above, and (y) actual volumes of production from such Target Oil and Gas Properties shall not be included in any calculation of “Actual Production Volumes” for purposes of determining compliance with Section 9.16(a) above.

(iii)With respect to each Subject Acquisition, from and after the earlier to occur of (A) the consummation of such Subject Acquisition and (B) the 90th day after the date on which the definitive purchase and sale agreement for such Subject Acquisition was entered into by the Borrower or any Guarantor, the Borrower shall be required to comply with Section 9.16(a) without giving effect to any of the provisions of clause (ii) above; provided that (x) if such Subject Acquisition is not consummated on or before the 90th day after the date on which the definitive purchase and sale agreement for such Subject Acquisition was entered into, any Reserve Report containing information with respect to the Target Oil and Gas Properties shall be deemed not to include such information and (y) if such Subject Acquisition is consummated on or before the 90th day after the date on which the definitive purchase and sale agreement for such Subject Acquisition was entered into, the actual volumes of production from the Target Oil and Gas Properties shall be fully taken into account for purposes of calculating Actual Production Volumes as if such Subject Acquisition had been consummated on the first day of the three-month period covered by the Quarter-End Production Report most recently delivered prior to the consummation of such Subject Acquisition pursuant to Section 8.01(m).

Section 9.17Change in Business; Corporate Structure; Accounting Change.

(a)Each of the Borrower and the Subsidiary Guarantors shall not, and shall not permit any Subsidiary to, engage in any business or activity other than (i) the business of the exploration for, and development, acquisition, and the production of Oil and Gas Properties, (ii) the business of marketing, processing, treating, gathering, and upstream transportation of Oil and Gas Properties produced by the Borrower and its Subsidiaries; (iii) developing raw land acquired or leased by the Borrower or its Subsidiaries in conjunction with the activities described in clause (i) or (ii) above, and remediating such land for resale; and (iv) the business of providing services to support any of the Borrower’s or its Subsidiary’s activities described in clause (i), (ii) or (iii) above.  The Borrower and Jones Parent shall not, and shall not permit any Subsidiary to engage in any activity or business, or acquire or make any other expenditure (whether such expenditure is capital, operating or otherwise) in or related to, any Oil and Gas Properties or businesses, in any event, which are not located within the geographical boundaries of the United States or the offshore area in the Gulf of Mexico over which the United States of America asserts jurisdiction.

(b)Each of the Borrower and the Guarantors shall not, and shall not permit any Subsidiary to, alter, amend or modify in any manner materially adverse to the Lenders any of its Organizational Documents.  In any event, the Borrower shall not permit any Subsidiary to (i) if such Subsidiary is a limited liability company, amend its limited liability company agreement to “opt in” to “security” status in accordance with Section 8.103 of the UCC or (ii) evidence its Equity Interests with a certificate without, in each case, the prior consent of the Administrative Agent.

(c)Except as set forth in Section 1.05, the Borrower and the Guarantors shall not, and shall not permit any Subsidiary to, make any significant change in accounting treatment or reporting practices, except as required by GAAP, or change the fiscal year of the Borrower or of any Subsidiary.

Section 9.18Parent Company.  Jones Parent shall not (i) hold any assets, (ii) incur, create, assume, or suffer to exist any Debt or any other liability or obligation, (iii) create, make or enter into any Investment or (iv) engage in any other activity or operation other than:

(a)its ownership of Equity Interests in the Borrower and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of Taxes, franchises, and other operational costs and expenses);

(b)participating in Tax, accounting and other administrative matters related to Jones Parent, the Borrower and its Subsidiaries;

(c)performance of its obligations under or in connection with its organizational documents or the Loan Documents;

(d)providing usual and customary indemnification to its officers and directors;

(e)the issuance and sale of its Equity Interests and repurchases thereof, and activities incidental thereto;

(f)the making of Investments in and contributions to the Borrower or any Subsidiary thereof;

(g)the making of dividends or distributions in return of capital to the holders of its Equity Interests;

(h)the incurrence of liabilities imposed by law, including Tax liabilities and other liabilities incidental to its existence and business and activities permitted hereunder;

(i)the incurrence of liabilities and exercise of rights under, and the performance of obligations pursuant to, (x) the Sabine Parent Guaranty and, (y) with the prior written consent of the Administrative Agent (which shall not be unreasonably withheld), any other guarantee of a similar scope and nature of obligations of a Credit Party (other than

obligations constituting Debt) under an acquisition agreement evidencing an acquisition that is permitted hereunder;

(j)the incurrence of liabilities and exercise of rights under, and the performance of obligations pursuant to, the Tax Receivable Agreement;

(k)performance of its obligations under or in connection with the Exchange Agreement;

(l)its guarantee of any Debt permitted under Section 9.02; and

(m)(x) ownership of other assets not to exceed $5,000,000 in the aggregate and (y) incurrences of Debt or other obligations not to exceed $5,000,000 in the aggregate at any time outstanding.

Notwithstanding the foregoing, (A) nothing contained in this Section 9.18 shall be construed as a consent to, or amendment or waiver of, any covenant, restriction, prohibition, limitation, condition or other term that is provided for in any other provision under this Agreement or any other Loan Document, including, but not limited to, the limitations on the Borrower and the Guarantors under the other provisions of this Article IX, and (B) Jones Parent will not create, incur, assume or permit to exist any Lien on any of its Properties (now owned or hereafter acquired) other than Liens granted under the Security Instruments and Excepted Liens arising in the ordinary course of business.

Section 9.19Sanctions; FCPA.

(a)Neither the Borrower nor Jones Parent shall, directly or indirectly, use the proceeds of the Advances, or lend, contribute or otherwise make available such proceeds to any Subsidiary, joint venture partner or other Person, (i) to fund any activities or business of or with any Restricted Party, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of Sanctions Laws, or (ii) in any other manner that would result in a violation of Sanctions Laws by Jones Parent, the Borrower or any Subsidiary or Affiliate of Jones Parent or the Borrower.

(b)No part of the proceeds of the Advances shall be used, directly or indirectly, by Jones Parent, the Borrower or any Subsidiary or Affiliate of Jones Parent or the Borrower in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of the Foreign Corrupt Practices Act of 1977, as amended, or any other applicable anti-corruption law.

(c)Jones Parent and the Borrower shall maintain in effect policies and procedures intended to promote compliance by Jones Parent, the Borrower, their respective Subsidiaries, and each of the foregoing’s directors, officers, employees, and agents with the Sanctions Laws, the Foreign Corrupt Practices Act of 1977, as amended, and any other applicable anti-corruption laws.

ARTICLE X
Events of Default; Remedies

Section 10.01Events of Default.  One or more of the following events shall constitute an “Event of Default”:

(a)the Borrower shall fail to pay any principal of any Loan or any reimbursement obligation in respect of any LC Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof, by acceleration or otherwise.

(b)the Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in Section 10.01(a)) payable under any Loan Document, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of three Business Days.

(c)any representation or warranty made or deemed made by or on behalf of the Borrower or any of the Guarantors in or in connection with any Loan Document or any amendment or modification of any Loan Document or waiver under such Loan Document, or in any report, certificate, financial statement or other document furnished pursuant to or in connection with any Loan Document or any amendment or modification thereof or waiver thereunder, shall prove to have been materially incorrect when made or deemed made (except that such materiality qualifier shall not be applicable to any representation or warranty that already is qualified or modified by materiality in the text thereof).

(d)the Borrower or any of the Guarantors shall fail to observe or perform any applicable covenant, condition or agreement contained in Section 8.01(l) (as to its name or state of organization), Section 8.01(o), Section 8.02, Section 8.03 (with respect to its legal existence), Section 8.09(a), Section 8.15, or in ARTICLE IX.

(e)the Borrower or any of the Guarantors shall fail to observe or perform any applicable covenant, condition or agreement contained in this Agreement (other than those specified in Section 10.01(a), Section 10.01(b) or Section 10.01(d)) or any other Loan Document, and such failure shall continue unremedied for a period of 30 days after the earlier to occur of (A) notice thereof from the Administrative Agent to the Borrower (which notice will be given at the request of any Lender) or (B) a Responsible Officer of the Borrower or applicable Guarantor otherwise becoming aware of such default.

(f)the Borrower or any of the Guarantors shall fail to make any payment (whether of principal or interest and regardless of amount) in respect of any Material Indebtedness, when and as the same shall become due and payable, after the expiration of any applicable period of grace and/or notice and cure.

(g)any event or condition occurs that results in any Material Indebtedness becoming due prior to its scheduled maturity or that enables or permits the holder or holders of any Material Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to become due, or to require the Redemption thereof or any offer to Redeem to be made in respect thereof, prior to its scheduled maturity or require the Borrower or any of the Guarantors to make an offer in respect thereof, after the expiration of any applicable period of grace and/or notice and cure; provided that this clause (h) shall not apply to secured Debt

permitted under Section 9.02(c) that becomes due as a result of the voluntary sale or transfer of the property or assets securing such Indebtedness.

(h)an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Borrower, Jones Parent, or any Guarantor or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower, Jones Parent, or any Guarantor or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for 60 days or an order or decree approving or ordering any of the foregoing shall be entered.

(i)the Borrower, Jones Parent, or any Guarantor shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in Section 10.01(h), (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower, Jones Parent, or any Guarantor or for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing.

(j)the Borrower, Jones Parent, or any Guarantor shall become unable, admit in writing its inability or fail generally to pay its debts as they become due.

(k)(i) one or more judgments for the payment of money in an aggregate amount in excess of $35,000,000 (to the extent not covered by a sound and reputable independent third party insurance as to which the insurer does not dispute coverage and is not subject to an insolvency proceeding) or (ii) any one or more non-monetary judgments that have, or could reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect, in each case, shall be rendered against the Borrower, Jones Parent, or any Guarantor and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Borrower, Jones Parent, or any Guarantor to enforce any such judgment.

(l)any Loan Document after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with its terms against the Borrower, Jones Parent, or a Guarantor party thereto or shall be repudiated by any of them, or cease to create a valid and perfected Lien of the priority required thereby on any of the collateral purported to be covered thereby, except (i) to the extent permitted by the terms of this Agreement or such other Loan Document, or (ii) with respect to collateral the aggregate value of which, for all such collateral, does not exceed at any time, $10,000,000, or the Borrower, Jones Parent, any Guarantor or any Affiliate shall so state in writing.

(m)an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when taken together with all other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower in an aggregate amount exceeding $35,000,000 in any calendar year, (ii) a Plan that is intended to be qualified under section 401(a) of the Code shall lose its qualified status and such event could reasonably be expected to have a Material Adverse Effect, or (iii) the Borrower, a Subsidiary Guarantor or any ERISA Affiliate shall engage in any “prohibited transaction,” as described in section 406 of ERISA or in section 4975 of the Code, involving any Plan and such event, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect.

(n)a Change in Control shall occur.

Section 10.02Remedies.

(a)In the case of an Event of Default other than one described in Section 10.01(h), Section 10.01(i) or Section 10.01(j), at any time thereafter during the continuance of such Event of Default, the Administrative Agent may, and at the request of the Required Lenders shall, by notice to the Borrower, take either or both of the following actions, at the same or different times:  (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Notes and the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the LC Exposure as provided in Section 2.08(j)), shall become due and payable immediately, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor; and in case of an Event of Default described in Section 10.01(h), Section 10.01(i) or Section 10.01(j), the Commitments shall automatically terminate and the Notes and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and the other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the LC Exposure as provided in Section 2.08(j)), shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor.

(b)In the case of the occurrence of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

(c)All proceeds realized from the liquidation or other disposition of collateral or otherwise received after maturity of the Notes, whether by acceleration or otherwise, shall be applied:

(i)first, to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Administrative Agent in its capacity as such;

(ii)second, pro rata to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Lenders under the Loan Documents;

(iii)third, pro rata to payment of accrued interest on the Loans;

(iv)fourth, pro rata to payment of principal outstanding on the Loans, Bank Product Obligations owing to any Lender or any Affiliate thereof, and Hedge Obligations owing to a Hedge Bank;

(v)fifth, pro rata to any other Indebtedness;

(vi)sixth, to serve as cash collateral to be held by the Administrative Agent to secure the LC Exposure; and

(vii)seventh, any excess, after all of the Indebtedness shall have been paid in full in cash (other than indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination), shall be paid to the Borrower or as otherwise required by any Governmental Requirement.

Excluded Swap Obligations with respect to any Guarantor shall not be paid with amounts received from such Guarantor or its assets, but at the discretion of the Administrative Agent and to the extent not prohibited under applicable law, appropriate adjustments shall be made with respect to payments from other Credit Parties to preserve the allocation to Indebtedness otherwise set forth above in this clause (c) assuming that, solely for purposes of such adjustments, Indebtedness includes Excluded Swap Obligations.

ARTICLE XI
The Administrative Agent

Section 11.01Appointment; Powers.  Each of the Lenders and the Issuing Bank hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof and the other Loan Documents, together with such actions and powers as are reasonably incidental thereto.

Section 11.02Duties and Obligations of Administrative Agent.  The Administrative Agent shall not have any duties or obligations except those expressly set forth in the Loan Documents.  Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing (the use of the term “agent” herein and in the other Loan Documents with reference to the Administrative Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law; rather, such term is used merely as a matter of market custom, and is intended to create or reflect only an administrative relationship between independent contracting parties), (b) the Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except as provided in Section 11.03, and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any Guarantor that is communicated to or

obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity.  The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or under any other Loan Document or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or in any other Loan Document, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, (v) the satisfaction of any condition set forth in ARTICLE VI or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent or as to those conditions precedent expressly required to be to the Administrative Agent’s satisfaction, (vi) the existence, value, perfection or priority of any collateral security or the financial or other condition of the Borrower and the Guarantors, or (vii) any failure by the Borrower or any other Person (other than itself) to perform any of its obligations hereunder or under any other Loan Document or the performance or observance of any covenants, agreements or other terms or conditions set forth herein or therein.  For purposes of determining compliance with the conditions specified in ARTICLE VI, each Lender shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received written notice from such Lender prior to the proposed closing date specifying its objection thereto.

Section 11.03Action by Administrative Agent.  The Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise in writing as directed by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02) and in all cases the Administrative Agent shall be fully justified in failing or refusing to act hereunder or under any other Loan Documents unless it shall (a) receive written instructions from the Required Lenders or the Lenders, as applicable, (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02) specifying the action to be taken and (b) be indemnified to its satisfaction by the Lenders against any and all liability and expenses which may be incurred by it by reason of taking or continuing to take any such action.  The instructions as aforesaid and any action taken or failure to act pursuant thereto by the Administrative Agent shall be binding on all of the Lenders.  If a Default has occurred and is continuing, then the Administrative Agent shall take such action with respect to such Default as shall be directed by the requisite Lenders in the written instructions (with indemnities) described in this Section 11.03, provided that, unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default as it shall deem advisable in the best interests of the Lenders.  In no event, however, shall the Administrative Agent be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement, the Loan Documents or applicable law.  The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders or the Lenders (or

such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02), and otherwise the Administrative Agent shall not be liable for any action taken or not taken by it hereunder or under any other Loan Document or under any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith INCLUDING ITS OWN ORDINARY NEGLIGENCE, except for its own gross negligence or willful misconduct.

Section 11.04Reliance by Administrative Agent.  The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person.  The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon and the Borrower, the Lenders and the Issuing Bank hereby waive the right to dispute the Administrative Agent’s record of such statement, except in the case of gross negligence or willful misconduct by the Administrative Agent.  The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.  The Administrative Agent may deem and treat the payee of any Note as the holder thereof for all purposes hereof unless and until a written notice of the assignment or transfer thereof permitted hereunder shall have been filed with the Administrative Agent.

Section 11.05Subagents.  The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent.  The Administrative Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties.  The exculpatory provisions of the preceding Sections of this ARTICLE XI shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

Section 11.06Resignation or Removal of Administrative Agent.  Subject to the appointment and acceptance of a successor Administrative Agent as provided in this Section 11.06, the Administrative Agent may resign at any time by notifying the Lenders, the Issuing Bank and the Borrower, and the Administrative Agent may be removed at any time with or without cause by the Required Lenders.  Upon any such resignation or removal, the Required Lenders shall have the right, in consultation with the Borrower, to appoint a successor.  If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation or removal as the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Lenders and the Issuing Bank, appoint a successor Administrative Agent.  Upon the acceptance of its appointment as Administrative Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations hereunder.  The fees payable by the Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor.  After the Administrative Agent’s resignation

hereunder, the provisions of this ARTICLE XI and Section 12.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Administrative Agent.

Section 11.07Administrative Agent as Lender.  The bank serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Administrative Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any of the Guarantors or other Affiliate thereof as if it were not the Administrative Agent hereunder.

Section 11.08No Reliance.

(a)Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and each other Loan Document to which it is a party.  Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document, any related agreement or any document furnished hereunder or thereunder.  The Administrative Agent shall not be required to keep itself informed as to the performance or observance by the Borrower or any Guarantor of this Agreement, the Loan Documents or any other document referred to or provided for herein or to inspect the Properties or books of the Borrower or any Guarantor.  Except for notices, reports and other documents and information expressly required to be furnished to the Lenders by the Administrative Agent hereunder, neither the Administrative Agent nor the Arranger shall have any duty or responsibility to provide any Lender with any credit or other information concerning the affairs, financial condition or business of the Borrower (or any of its Affiliates) which may come into the possession of the Administrative Agent or any of its Affiliates.  In this regard, each Lender acknowledges that Bracewell & Giuliani LLP is acting in this transaction as special counsel to the Administrative Agent only, except to the extent otherwise expressly stated in any legal opinion or any Loan Document.  Each other party hereto will consult with its own legal counsel to the extent that it deems necessary in connection with the Loan Documents and the matters contemplated therein.

(b)The Lenders acknowledge that the Administrative Agent and the Arranger are acting solely in administrative capacities with respect to structuring and syndication of this facility and have no duties, responsibilities or liabilities under this Agreement and the other Loan Documents other than their administrative duties, responsibilities and liabilities specifically as set forth in the Loan Documents and in their capacity as Lenders hereunder.  In structuring, arranging or syndicating this Agreement, each Lender acknowledges that the Administrative Agent and the Arranger may be an agent or lender under these Notes, other loans or other securities and waives any existing or future conflicts of interest associated with their role in such other debt instruments.  If in the administration of this facility or any other debt instrument, the Administrative Agent determines (or is given written notice by any Lender that a conflict exists),

then it shall eliminate such conflict within ninety (90) days or resign pursuant to Section 11.06 and shall have no liability for action taken or not taken while such conflict existed.

Section 11.09Administrative Agent May File Proofs of Claim.

In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Borrower, Jones Parent, or any Guarantor, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Section 12.03) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Section 12.03.

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

Section 11.10Authority of Administrative Agent to Release Collateral and Liens.

(a)Each Lender, the Issuing Bank and each other Secured Party (by their acceptance of the benefits of any Lien encumbering the Mortgaged Property) hereby authorizes the Administrative Agent to release any collateral that is permitted to be sold or released pursuant to the terms of the Loan Documents.  Each Lender, the Issuing Bank and each other Secured Party (by their acceptance of the benefits of any Lien encumbering the Mortgaged Property) hereby authorizes the Administrative Agent to execute and deliver to the Borrower, at the Borrower’s sole cost and expense, any and all releases of Liens, termination statements, assignments or other documents reasonably requested by the Borrower in connection with any sale or other disposition of Property to the extent such sale or other disposition is permitted by the terms of Section 9.11 or is otherwise authorized by the terms of the Loan Documents.  Upon the request of the Administrative Agent at any time, the Secured Parties will confirm in writing

the Administrative Agent’s authority to release particular types or items of Collateral pursuant to this Section 11.10.

(b)Notwithstanding anything contained in any of the Loan Documents to the contrary, the Credit Parties, the Administrative Agent, and each Secured Party hereby agree that no Secured Party shall have any right individually to realize upon any of the Collateral or to enforce the Guaranties, it being understood and agreed that all powers, rights and remedies hereunder and under the Security Instruments may be exercised solely by Administrative Agent on behalf of the Secured Parties in accordance with the terms hereof and the other Loan Documents.  By accepting the benefit of the Liens granted pursuant to the Security Instruments, each Secured Party not party hereto hereby agrees to the terms of this paragraph (c).

Section 11.11The Arranger; Other Agents.  Neither the Arranger nor any of the Co-Syndication Agents nor any of the Co-Documentation Agents identified on the cover page to this Agreement shall have any duties, responsibilities or liabilities under this Agreement and the other Loan Documents other than their respective duties, responsibilities and liabilities in their respective capacities as a Lender hereunder.

ARTICLE XII
Miscellaneous

Section 12.01Notices.

(a)Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to Section 12.01(b)), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

(i)if to the Borrower, to it at:

Jones Energy Holdings, LLC
807 Las Cimas Parkway, Suite 350
Austin, Texas  78746
Attention: Robert J. Brooks, Chief Financial Officer
Facsimile:  (512) 328-5394

(ii)if to the Administrative Agent or the Issuing Bank, to it at

Wells Fargo Bank, National Association

1740 Broadway, MAC C7300-034

Denver, Colorado 80209

Phone:303.863.5938

Fax:303.863.5533

Attn: Dave McEvoy

with a copy to:

Wells Fargo Bank, National Association

1000 Louisiana, 9th Floor, MAC T5002-090

Houston, Texas 77002

Fax:713.739.1087

Attn: Paul Squires

with a copy to the Administrative Agent at the address noted above.

(iii)if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

(b)Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to ARTICLE II, ARTICLE III, ARTICLE IV and ARTICLE V unless otherwise agreed by the Administrative Agent and the applicable Lender.  The Administrative Agent or the Borrower may, in their discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c)Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto.  All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

Section 12.02Waivers; Amendments.

(a)No failure on the part of the Administrative Agent, the Issuing Bank or any Lender to exercise and no delay in exercising, and no course of dealing with respect to, any right, power or privilege, or any abandonment or discontinuance of steps to enforce such right, power or privilege, under any of the Loan Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under any of the Loan Documents preclude any other or further exercise thereof or the exercise of any other right, power or privilege.  The rights and remedies of the Administrative Agent, the Issuing Bank and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have.  No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by Section 12.02(b), and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given.  Without limiting the generality of the foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent, any Lender or the Issuing Bank may have had notice or knowledge of such Default at the time.

(b)Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Majority Lenders or by the Borrower and the Administrative Agent with the consent of the Majority Lenders; provided

that no such agreement shall (i) increase the Commitment or the Maximum Credit Amount of any Lender without the written consent of such Lender, (ii) increase the Borrowing Base without the written consent of each Lender, decrease or maintain the Borrowing Base without the consent of the Required Lenders, or modify Section 2.07 in any manner adverse to the Lenders without the consent of each Lender (other than a Defaulting Lender); provided that, any waiver, amendment or modification of Section 2.07(e)(i) may be effected with the consent of the Required Lenders, (iii) reduce the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (iv) postpone the scheduled date of payment or prepayment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone or extend the Termination Date without the written consent of each Lender affected thereby, (v) change Section 4.01(b) or Section 4.01(c) in a manner that would alter the pro rata sharing of payments required thereby in a manner adverse to any Lender, without the written consent of such Lender, (vi) waive or amend Section 3.04(c), Section 6.01 or Section 10.02(c), without the written consent of each Lender (other than a Defaulting Lender), (vii) release any Guarantor (except as set forth in the Guarantee and Collateral Agreement), release all or substantially all of the collateral (other than as provided in Section 11.10), or reduce the percentage set forth in Section 8.13(a) to less than 80%, without the written consent of each Lender (other than a Defaulting Lender), or (viii) change any of the provisions of this Section 12.02(b) or the definitions of “Required Lenders” or “Majority Lenders” or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender (other than a Defaulting Lender); provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent, or the Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent, or the Issuing Bank, as the case may be.  Notwithstanding the foregoing, any supplement to Schedule 7.14 (Subsidiaries) or Schedule 7.15 (Locations of Business and Offices) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

Section 12.03Expenses, Indemnity; Damage Waiver.

(a)The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including, without limitation, the reasonable fees, charges and disbursements of counsel and other outside consultants for the Administrative Agent, the reasonable travel, photocopy, mailing, courier, telephone and other similar expenses, and the cost of environmental audits and surveys and appraisals, in connection with the syndication of the credit facilities provided for herein, the preparation, negotiation, execution, delivery and administration (both before and after the execution hereof and including advice of counsel to the Administrative Agent as to the rights and duties of the Administrative Agent and the Lenders with respect thereto) of this Agreement and the other Loan Documents and any amendments, modifications or waivers of or consents related to the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all

costs, expenses, and other charges (other than Taxes, which are addressed in Section 5.03(b)) incurred by the Administrative Agent or any Lender in connection with any filing, registration, recording or perfection of any security interest contemplated by this Agreement or any Security Instrument or any other document referred to therein, (iii) all reasonable out-of-pocket expenses incurred by the Issuing Bank in connection with the issuance, amendment, renewal or extension of any Letter of Credit or any demand for payment thereunder, (iv) all out-of-pocket expenses incurred by the Administrative Agent, the Issuing Bank or any Lender, including the reasonable fees, charges and disbursements of any counsel for the Administrative Agent, the Issuing Bank or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement or any other Loan Document, including its rights under this Section 12.03, or in connection with the Loans made or Letters of Credit issued hereunder, including, without limitation, all such out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans or Letters of Credit.

(b)THE BORROWER SHALL, AND DOES HEREBY, INDEMNIFY THE ADMINISTRATIVE AGENT, THE ARRANGER, THE ISSUING BANK AND EACH LENDER, AND EACH RELATED PARTY OF ANY OF THE FOREGOING PERSONS (EACH SUCH PERSON BEING CALLED AN “INDEMNITEE”) AGAINST, AND HOLD EACH INDEMNITEE HARMLESS FROM, ANY AND ALL LOSSES, CLAIMS, DAMAGES, LIABILITIES AND RELATED EXPENSES, INCLUDING THE REASONABLE FEES, CHARGES AND DISBURSEMENTS OF ANY COUNSEL FOR ANY INDEMNITEE, INCURRED BY OR ASSERTED AGAINST ANY INDEMNITEE (WHETHER ASSERTED BY ANY THIRD PARTY OR BY THE BORROWER OR ANY OTHER CREDIT PARTY) AND ARISING OUT OF, IN CONNECTION WITH, OR AS A RESULT OF (i) THE EXECUTION OR DELIVERY OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR ANY AGREEMENT OR INSTRUMENT CONTEMPLATED HEREBY OR THEREBY, THE PERFORMANCE BY THE PARTIES HERETO OR THE PARTIES TO ANY OTHER LOAN DOCUMENT OF THEIR RESPECTIVE OBLIGATIONS HEREUNDER OR THEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS CONTEMPLATED HEREBY OR BY ANY OTHER LOAN DOCUMENT, (ii) THE FAILURE OF THE BORROWER OR ANY OF THE GUARANTORS TO COMPLY WITH THE TERMS OF ANY LOAN DOCUMENT, INCLUDING THIS AGREEMENT, OR WITH ANY GOVERNMENTAL REQUIREMENT, (iii) ANY INACCURACY OF ANY REPRESENTATION OR ANY BREACH OF ANY WARRANTY OR COVENANT OF THE BORROWER OR ANY OF THE GUARANTORS SET FORTH IN ANY OF THE LOAN DOCUMENTS OR ANY INSTRUMENTS, DOCUMENTS OR CERTIFICATIONS DELIVERED IN CONNECTION THEREWITH, (iv) ANY LOAN OR LETTER OF CREDIT OR THE USE OF THE PROCEEDS THEREFROM, INCLUDING, WITHOUT LIMITATION, (A) ANY REFUSAL BY THE ISSUING BANK TO HONOR A DEMAND FOR PAYMENT UNDER A LETTER OF CREDIT IF THE DOCUMENTS PRESENTED IN CONNECTION WITH SUCH DEMAND DO NOT STRICTLY COMPLY WITH THE TERMS OF SUCH LETTER OF CREDIT, OR (B) THE PAYMENT OF A DRAWING UNDER ANY LETTER OF CREDIT NOTWITHSTANDING THE NON-COMPLIANCE, NON-DELIVERY OR OTHER IMPROPER PRESENTATION OF THE DOCUMENTS PRESENTED IN CONNECTION THEREWITH, (v) ANY OTHER ASPECT OF THE LOAN DOCUMENTS, (vi) THE OPERATIONS OF THE BUSINESS OF THE BORROWER AND THE GUARANTORS BY THE BORROWER AND THE GUARANTORS, (vii) ANY ASSERTION

THAT THE LENDERS WERE NOT ENTITLED TO RECEIVE THE PROCEEDS RECEIVED PURSUANT TO THE SECURITY INSTRUMENTS, (viii) ANY ENVIRONMENTAL LAW APPLICABLE TO THE BORROWER OR ANY OF THE GUARANTORS OR ANY OF THEIR PROPERTIES, INCLUDING WITHOUT LIMITATION, THE PRESENCE, GENERATION, STORAGE, RELEASE, THREATENED RELEASE, USE, TRANSPORT, DISPOSAL, ARRANGEMENT OF DISPOSAL OR TREATMENT OF OIL, OIL AND GAS WASTES, SOLID WASTES OR HAZARDOUS SUBSTANCES ON ANY OF THEIR PROPERTIES, (ix) THE BREACH OR NON-COMPLIANCE BY THE BORROWER OR ANY OF THE GUARANTORS WITH ANY ENVIRONMENTAL LAW APPLICABLE TO THE BORROWER OR ANY OF THE GUARANTORS, (x) THE PAST OWNERSHIP BY THE BORROWER OR ANY OF THE GUARANTORS OF ANY OF THEIR PROPERTIES OR PAST ACTIVITY ON ANY OF THEIR PROPERTIES WHICH, THOUGH LAWFUL AND FULLY PERMISSIBLE AT THE TIME, COULD RESULT IN PRESENT LIABILITY, (xi) THE PRESENCE, USE, RELEASE, STORAGE, TREATMENT, DISPOSAL, GENERATION, THREATENED RELEASE, TRANSPORT, ARRANGEMENT FOR TRANSPORT OR ARRANGEMENT FOR DISPOSAL OF OIL, OIL AND GAS WASTES, SOLID WASTES OR HAZARDOUS SUBSTANCES ON OR AT ANY OF THE PROPERTIES OWNED OR OPERATED BY THE BORROWER OR ANY OF THE GUARANTORS OR ANY ACTUAL OR ALLEGED PRESENCE OR RELEASE OF HAZARDOUS MATERIALS ON OR FROM ANY PROPERTY OWNED OR OPERATED BY THE BORROWER OR ANY OF THE GUARANTORS, (xii) ANY ENVIRONMENTAL LIABILITY RELATED IN ANY WAY TO THE BORROWER OR ANY OF THE GUARANTORS, OR (xiii) ANY OTHER ENVIRONMENTAL, HEALTH OR SAFETY CONDITION IN CONNECTION WITH THE LOAN DOCUMENTS, OR (xiv) ANY ACTUAL OR PROSPECTIVE CLAIM, LITIGATION, INVESTIGATION OR PROCEEDING, IN EACH CASE, RELATING TO ANY OF THE FOREGOING, AND IN EACH CASE, WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY AND REGARDLESS OF WHETHER ANY INDEMNITEE IS A PARTY THERETO, AND SUCH INDEMNITY SHALL EXTEND TO EACH INDEMNITEE NOTWITHSTANDING THE SOLE OR CONCURRENT NEGLIGENCE OF EVERY KIND OR CHARACTER WHATSOEVER, WHETHER ACTIVE OR PASSIVE, WHETHER AN AFFIRMATIVE ACT OR AN OMISSION, INCLUDING WITHOUT LIMITATION, ALL TYPES OF NEGLIGENT CONDUCT IDENTIFIED IN THE RESTATEMENT (SECOND) OF TORTS OF ONE OR MORE OF THE INDEMNITEES OR BY REASON OF STRICT LIABILITY IMPOSED WITHOUT FAULT ON ANY ONE OR MORE OF THE INDEMNITEES; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY INDEMNITEE, BE AVAILABLE TO THE EXTENT THAT (I) SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED EXPENSES ARE DETERMINED TO HAVE RESULTED FROM THE GROSS NEGLIGENCE, BAD FAITH OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE OR (II) SUCH CLAIMS (OTHER THAN CLAIMS AGAINST OR BY THE ADMINISTRATIVE AGENT, THE ARRANGER, OR THE ISSUING BANK) ARE SOLELY BETWEEN INDEMNITEES SO LONG AS SUCH CLAIM DOES NOT INVOLVE, OR RESULT FROM, AN ACTION OR INACTION BY THE BORROWER OR ANY RELATED PARTY OF THE BORROWER, IN EACH CASE OF THE FOREGOING CLAUSES (I), AND (II), AS DETERMINED BY A FINAL NON-APPEALABLE JUDGMENT OF A COURT OF COMPETENT JURISDICTION.

Notwithstanding anything to the contrary in this Section 12.03(b), under no circumstances shall the provisions of this Section 12.03(b) be construed to cover any expenses not otherwise reimbursable under Section 12.03(a).  This Section 12.03(b) shall not apply with respect to Taxes other than any Taxes that represent losses, claims, damages, etc. arising from any non-Tax claim.

(c)To the extent that the Borrower fails to pay any amount required to be paid by it to the Administrative Agent, the Arranger or the Issuing Bank under Section 12.03(a) or (b), each Lender severally agrees to pay to the Administrative Agent, the Arranger or the Issuing Bank, as the case may be, such Lender’s Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent, the Arranger or the Issuing Bank in its capacity as such.

(d)To the extent permitted by applicable law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

(e)All amounts due under this Section 12.03 shall be payable not later than three days after written demand therefor.

Section 12.04Successors and Assigns.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of the Issuing Bank that issues any Letter of Credit), except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 12.04 or as required under Section 5.04.  Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of the Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in Section 12.04(c)) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Issuing Bank and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)(i) Subject to the conditions set forth in Section 12.04(b)(ii), any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld, it being understood that the Borrower may withhold its consent to any such assignment if such assignment would result in a “Termination Event” or an “Event of Default” or a similar event under any Swap Agreement to which the assignor or any Affiliate of the assignor is a party and such

“Termination Event,” “Event of Default” or similar event would result in an Event of Default under Section 10.01(g) of this Agreement (and such withholding of consent shall be deemed to be reasonable)) of:

(A)the Borrower, provided that (i) no consent of the Borrower shall be required if such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund, or if an Event of Default has occurred and is continuing; and (ii) the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within 10 days after having received notice thereof; and

(B)the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment to an assignee that is a Lender immediately prior to giving effect to such assignment.

(ii)Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $1,000,000 unless each of the Borrower and the Administrative Agent otherwise consent, provided that no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing;

(B)each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; and

(D)the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(iii)Subject to Section 12.04(b)(iv) and the acceptance and recording thereof, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 5.01, Section 5.02, Section 5.03 and Section 12.03 with respect to facts and circumstances occurring prior to the effective date of such assignment and

subject to any applicable requirements thereof).  Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.04(c).

(iv)The Administrative Agent, acting for this purpose as a non-fiduciary agent of the Borrower, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amounts (and stated interest) of the Loans and reimbursement obligations with respect to LC Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the “Register”).  The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent, the Issuing Bank and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary.  The Register shall be available for inspection by the Borrower, the Issuing Bank and any Lender, at any reasonable time and from time to time upon reasonable prior notice.  In connection with any changes to the Register, if necessary, the Administrative Agent will reflect the revisions on Annex I and forward a copy of such revised Annex I to the Borrower, the Issuing Bank and each Lender.

(v)Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in Section 12.04(b) and any written consent to such assignment required by Section 12.04(b), the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register.  No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this Section 12.04(b).

(c)Any Lender may, without the consent of the Borrower, the Administrative Agent or the Issuing Bank, sell participations to one or more banks or other entities (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent, the Issuing Bank and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement and (D) such Lender shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register that contains the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans, Commitments and other obligations under the Loan Documents (the “Participant Register”), but such Lender shall not have any obligation to disclose all or a portion of such register (including the identity of any Participant or any information relating to a Participant’s interest in any Commitment, Loan, Letter of Credit or other obligation under the Loan Documents) to any Person other than if necessary to establish that a Commitment, Loan, Letter of Credit or other obligation under the Loan Documents is in registered form for Tax purposes.  The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each

Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.  Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the proviso to Section 12.02 that affects such Participant.  In addition such agreement must provide that the Participant be bound by the provisions of Section 12.03.  The Borrower agrees that each Participant shall be entitled to the benefits of Section 5.01, Section 5.02 and Section 5.03 (subject to the requirements and limitations therein, including the requirements under Section 5.03(e) and Section 5.03(f) (it being understood that the documentation required under Section 5.03(e) and Section 5.03(f) shall be delivered to the participating Lender)) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.04(b); provided that such Participant (A) agrees to be subject to the provisions of Section 5.04 as if it were an assignee under Section 12.04(b); and (B) shall not be entitled to receive any greater payment under Section 5.01 or Section 5.03, with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation.  Each Lender that sells a participation agrees, at the Borrower’s request and expense, to use reasonable efforts to cooperate with the Borrower to effectuate the provisions of Section 5.04(b) with respect to any Participant.  To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 12.08 as though it were a Lender, provided such Participant agrees to be subject to Section 4.01(c) as though it were a Lender.

(d)Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including, without limitation, any pledge or assignment to secure obligations to a Federal Reserve Bank or any other central bank having jurisdiction over such Lender, and this (d) shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(e)Notwithstanding any other provisions of this Section 12.04, no transfer or assignment of the interests or obligations of any Lender or any grant of participations therein shall be permitted if such transfer, assignment or grant would require the Borrower or any Guarantor to file a registration statement with the SEC or to qualify the Loans under the “Blue Sky” laws of any state.

Section 12.05Survival; Revival; Reinstatement.

(a)All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the

Administrative Agent, the Issuing Bank or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid or any Letter of Credit is outstanding and so long as the Commitments have not expired or terminated.  The provisions of Section 5.01, Section 5.02, Section 5.03 and Section 12.03 and ARTICLE XI shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the Commitments or the termination of this Agreement, any other Loan Document or any provision hereof or thereof.

(b)To the extent that any payments on the Indebtedness or proceeds of any collateral are subsequently invalidated, declared to be fraudulent or preferential, set aside or required to be repaid to a trustee, debtor in possession, receiver or other Person under any bankruptcy law, common law or equitable cause, then to such extent, the Indebtedness so satisfied shall be revived and continue as if such payment or proceeds had not been received and the Administrative Agent’s and the Lenders’ Liens, security interests, rights, powers and remedies under this Agreement and each Loan Document shall continue in full force and effect.  In such event, each Loan Document shall be automatically reinstated and the Borrower shall take such action as may be reasonably requested by the Administrative Agent and the Lenders to effect such reinstatement.

Section 12.06Counterparts; Integration; Effectiveness.

(a)This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.

(b)This Agreement, the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and thereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof and thereof.

(c)This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.  Delivery of an executed counterpart of a signature page of this Agreement by facsimile or electronic mail (i.e. PDF) shall be effective as delivery of a manually executed counterpart of this Agreement.

Section 12.07Severability.  Any provision of this Agreement or any other Loan Document held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

Section 12.08Right of Setoff.  If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations (of whatsoever kind, including, without limitations obligations under Swap Agreements) at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower or any Guarantor against any of and all the obligations of the Borrower or any Guarantor owed to such Lender now or hereafter existing under this Agreement or any other Loan Document, irrespective of whether or not such Lender shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured.  The rights of each Lender under this Section 12.08 are in addition to other rights and remedies (including other rights of setoff) which such Lender or its Affiliates may have.

Section 12.09GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS.

(a)THIS AGREEMENT AND THE NOTES SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS EXCEPT TO THE EXTENT THAT UNITED STATES FEDERAL LAW PERMITS ANY LENDER TO CONTRACT FOR, CHARGE, RECEIVE, RESERVE OR TAKE INTEREST AT THE RATE ALLOWED BY THE LAWS OF THE STATE WHERE SUCH LENDER IS LOCATED.  CHAPTER 346 OF THE TEXAS FINANCE CODE (WHICH REGULATES CERTAIN REVOLVING CREDIT LOAN ACCOUNTS AND REVOLVING TRI-PARTY ACCOUNTS) SHALL NOT APPLY TO THIS AGREEMENT OR THE NOTES.

(b)ANY LEGAL ACTION OR PROCEEDING WITH RESPECT TO THE LOAN DOCUMENTS SHALL BE BROUGHT IN THE COURTS OF THE STATE OF TEXAS OR OF THE UNITED STATES OF AMERICA FOR THE SOUTHERN DISTRICT OF TEXAS, AND, BY EXECUTION AND DELIVERY OF THIS AGREEMENT, EACH PARTY HEREBY ACCEPTS FOR ITSELF AND (TO THE EXTENT PERMITTED BY LAW) IN RESPECT OF ITS PROPERTY, GENERALLY AND UNCONDITIONALLY, THE JURISDICTION OF THE AFORESAID COURTS.  EACH PARTY HEREBY IRREVOCABLY WAIVES ANY OBJECTION, INCLUDING, WITHOUT LIMITATION, ANY OBJECTION TO THE LAYING OF VENUE OR BASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW OR HEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION OR PROCEEDING IN SUCH RESPECTIVE JURISDICTIONS.

(c)EACH PARTY IRREVOCABLY CONSENTS TO THE SERVICE OF PROCESS OF ANY OF THE AFOREMENTIONED COURTS IN ANY SUCH ACTION OR PROCEEDING BY THE MAILING OF COPIES THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, TO IT AT THE ADDRESS SPECIFIED IN SECTION 12.01 OR SUCH OTHER ADDRESS AS IS SPECIFIED PURSUANT TO SECTION 12.01 (OR ITS ASSIGNMENT AND ASSUMPTION), SUCH SERVICE TO BECOME EFFECTIVE THIRTY (30) DAYS AFTER SUCH MAILING.  NOTHING HEREIN SHALL AFFECT THE RIGHT OF A PARTY OR ANY HOLDER OF A NOTE TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO COMMENCE

LEGAL PROCEEDINGS OR OTHERWISE PROCEED AGAINST ANOTHER PARTY IN ANY OTHER JURISDICTION.

(d)EACH PARTY HEREBY (i) IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN; (ii) IRREVOCABLY WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION ANY SPECIAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES, OR DAMAGES OTHER THAN, OR IN ADDITION TO, ACTUAL DAMAGES; PROVIDED, THAT, FOR THE AVOIDANCE OF DOUBT, NOTHING CONTAINED IN THIS CLAUSE (ii) SHALL LIMIT ANY CREDIT PARTY’S INDEMNIFICATION OBLIGATIONS TO THE EXTENT SET FORTH IN SECTION 12.03(b) ABOVE TO THE EXTENT SUCH SPECIAL, INDIRECT, CONSEQUENTIAL OR PUNITIVE DAMAGES ARE INCLUDED IN ANY THIRD PARTY CLAIM IN CONNECTION WITH WHICH SUCH INDEMNITEE IS OTHERWISE ENTITLED TO INDEMNIFICATION HEREUNDER; (iii) CERTIFIES THAT NO PARTY HERETO NOR ANY REPRESENTATIVE OR AGENT OF COUNSEL FOR ANY PARTY HERETO HAS REPRESENTED, EXPRESSLY OR OTHERWISE, OR IMPLIED THAT SUCH PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVERS, AND (iv) ACKNOWLEDGES THAT IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT, THE LOAN DOCUMENTS AND THE TRANSACTIONS CONTEMPLATED HEREBY AND THEREBY BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS CONTAINED IN THIS SECTION 12.09.

Section 12.10Headings.  Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Section 12.11Confidentiality.  Each of the Administrative Agent, the Issuing Bank and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement or any other Loan Document, (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any suit, action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section 12.11, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any Swap Agreement relating to the Borrower and its obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 12.11 or (ii) becomes available to the Administrative Agent, the Issuing

Bank or any Lender on a nonconfidential basis from a source other than the Borrower.  For the purposes of this Section 12.11, “Information” means all information received from the Borrower or any of its Subsidiaries relating to the Borrower’s or any of its Subsidiaries’ businesses, other than any such information that is available to the Administrative Agent, the Issuing Bank or any Lender on a nonconfidential basis prior to disclosure by the Borrower or any of its Subsidiaries; provided that, in the case of information received from the Borrower or any of its Subsidiaries after the date hereof, such information is hereby deemed at the time of delivery as confidential.  Any Person required to maintain the confidentiality of Information as provided in this Section 12.11 shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.

Section 12.12Interest Rate Limitation.  It is the intention of the parties hereto that each Lender shall conform strictly to usury laws applicable to it.  Accordingly, if the transactions contemplated hereby would be usurious as to any Lender under laws applicable to it (including the laws of the United States of America and the State of Texas or any other jurisdiction whose laws may be mandatorily applicable to such Lender notwithstanding the other provisions of this Agreement), then, in that event, notwithstanding anything to the contrary in any of the Loan Documents or any agreement entered into in connection with or as security for the Notes, it is agreed as follows:  (i) the aggregate of all consideration which constitutes interest under law applicable to any Lender that is contracted for, taken, reserved, charged or received by such Lender under any of the Loan Documents or agreements or otherwise in connection with the Notes shall under no circumstances exceed the maximum amount allowed by such applicable law, and any excess shall be canceled automatically and if theretofore paid shall be credited by such Lender on the principal amount of the Indebtedness (or, to the extent that the principal amount of the Indebtedness shall have been or would thereby be paid in full (other than indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination), refunded by such Lender to the Borrower); and (ii) in the event that the maturity of the Notes is accelerated by reason of an election of the holder thereof resulting from any Event of Default under this Agreement or otherwise, or in the event of any required or permitted prepayment, then such consideration that constitutes interest under law applicable to any Lender may never include more than the maximum amount allowed by such applicable law, and excess interest, if any, provided for in this Agreement or otherwise shall be canceled automatically by such Lender as of the date of such acceleration or prepayment and, if theretofore paid, shall be credited by such Lender on the principal amount of the Indebtedness (or, to the extent that the principal amount of the Indebtedness shall have been or would thereby be paid in full (other than indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination), refunded by such Lender to the Borrower).  All sums paid or agreed to be paid to any Lender for the use, forbearance or detention of sums due hereunder shall, to the extent permitted by law applicable to such Lender, be amortized, prorated, allocated and spread throughout the stated term of the Loans evidenced by the Notes until payment in full so that the rate or amount of interest on account of any Loans hereunder does not exceed the maximum amount allowed by such applicable law.  If at any time and from time to time (i) the amount of interest payable to any Lender on any date shall be computed at the Highest Lawful Rate applicable to such Lender pursuant to this Section 12.12 and (ii) in respect of any subsequent interest computation period the amount of interest otherwise payable to such Lender would be less than the amount of

interest payable to such Lender computed at the Highest Lawful Rate applicable to such Lender, then the amount of interest payable to such Lender in respect of such subsequent interest computation period shall continue to be computed at the Highest Lawful Rate applicable to such Lender until the total amount of interest payable to such Lender shall equal the total amount of interest which would have been payable to such Lender if the total amount of interest had been computed without giving effect to this Section 12.12.  To the extent that Chapter 303 of the Texas Finance Code is relevant for the purpose of determining the Highest Lawful Rate applicable to a Lender, such Lender elects to determine the applicable rate ceiling under such Chapter by the weekly ceiling from time to time in effect.  Chapter 346 of the Texas Finance Code does not apply to the Borrower’s obligations hereunder.

Section 12.13EXCULPATION PROVISIONS.  EACH OF THE PARTIES HERETO SPECIFICALLY AGREES THAT IT HAS A DUTY TO READ THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS AND AGREES THAT IT IS CHARGED WITH NOTICE AND KNOWLEDGE OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; THAT IT HAS IN FACT READ THIS AGREEMENT AND IS FULLY INFORMED AND HAS FULL NOTICE AND KNOWLEDGE OF THE TERMS, CONDITIONS AND EFFECTS OF THIS AGREEMENT; THAT IT HAS BEEN REPRESENTED BY INDEPENDENT LEGAL COUNSEL OF ITS CHOICE THROUGHOUT THE NEGOTIATIONS PRECEDING ITS EXECUTION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND HAS RECEIVED THE ADVICE OF ITS ATTORNEY IN ENTERING INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND THAT IT RECOGNIZES THAT CERTAIN OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS RESULT IN ONE PARTY ASSUMING THE LIABILITY INHERENT IN SOME ASPECTS OF THE TRANSACTION AND RELIEVING THE OTHER PARTY OF ITS RESPONSIBILITY FOR SUCH LIABILITY.  EACH PARTY HERETO AGREES AND COVENANTS THAT IT WILL NOT CONTEST THE VALIDITY OR ENFORCEABILITY OF ANY EXCULPATORY PROVISION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS ON THE BASIS THAT THE PARTY HAD NO NOTICE OR KNOWLEDGE OF SUCH PROVISION OR THAT THE PROVISION IS NOT “CONSPICUOUS.”

Section 12.14Collateral Matters; Swap Agreements.

(a)The benefit of the Security Instruments and of the provisions of this Agreement relating to any collateral securing the Indebtedness shall also extend to and be available to Hedge Banks on a pro rata basis in respect of any Hedge Obligations (to the extent limited in the definition thereof) and to the Lenders and their respective Affiliates on a pro rata basis in respect of any Bank Product Obligations.  No Lender or any Affiliate of a Lender shall have any voting rights under any Loan Document as a result of the existence of such Hedge Obligations or such Bank Production Obligations.  No Lender or any Affiliate of a Lender, in its capacity as a Hedge Bank or as the provider of Bank Products, that obtains the benefits of any Guarantee and Collateral Agreement or any Security Instrument by virtue of the provisions hereof or of any Guarantee and Collateral Agreement or any Loan Document shall have any right to notice of any action or to consent to, direct or object to any action hereunder (including under Section 12.02) or under any other Loan Document or otherwise in respect of any collateral or Mortgaged Property (including the release or impairment of any collateral or Mortgaged

Property) other than in its capacity as a Lender and, in such case, only to the extent expressly provided in the Loan Documents.  Notwithstanding anything to the contrary contained herein or in any other Loan Document, no Hedge Obligations and no Bank Product Obligations shall be Indebtedness hereunder or under any other Loan Document or “Indebtedness” as defined in any Loan Documents after all Commitments have terminated or expired, all Indebtedness (other than Hedge Obligations, Bank Product Obligations and indemnities and other contingent obligations not then due and payable and as to which no claim has been made as of the time of determination) have been paid in full in cash and all Letters of Credit have expired or terminated or the LC Exposure has been cash collateralized (or as to which other arrangements satisfactory to the Administrative Agent and the Issuing Bank shall have been made) as provided for herein.

Section 12.15No Third Party Beneficiaries.  This Agreement, the other Loan Documents, and the agreement of the Lenders to make Loans and the Issuing Bank to issue, amend, renew or extend Letters of Credit hereunder are solely for the benefit of the Borrower, and no other Person (including, without limitation, any Subsidiary of the Borrower, any obligor, contractor, subcontractor, supplier or materialsman) shall have any rights, claims, remedies or privileges hereunder or under any other Loan Document against the Administrative Agent, the Issuing Bank or any Lender for any reason whatsoever.  There are no third party beneficiaries.

Section 12.16USA Patriot Act Notice.  Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”), it is required to obtain, verify and record information that identifies the Borrower and each other Credit Party, which information includes the name and address of the Borrower, each other Credit Party and other information that will allow such Lender to identify the Borrower in accordance with the Act.

Section 12.17Keepwell.  Each Qualified ECP Guarantor hereby jointly and severally absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each other Credit Party to honor all of its obligations under this Agreement in respect of Swap Obligations (provided, however, that each Qualified ECP Guarantor shall only be liable under this Section 12.17 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 12.17, or otherwise under this Agreement, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of each Qualified ECP Guarantor under this Section shall remain in full force and effect until the Security Termination (as defined in the Guarantee and Collateral Agreement) has occurred.  Each Qualified ECP Guarantor intends that this Section 12.17 constitute, and this Section 12.17 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Credit Party for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

Section 12.18Flood Insurance Regulations.  Wells Fargo has adopted internal policies and procedures that address requirements placed on federally regulated lenders under the National Flood Insurance Reform Act of 1994 and related legislation and regulatory requirements (the “Flood Laws”).  If applicable, Wells Fargo, as administrative agent, will post on the applicable electronic platform (or otherwise distribute to each Lender) documents that it receives in connection with the Flood Laws; however, Wells Fargo reminds each Lender and

Participant that, pursuant to the Flood Laws, each federally regulated lender (whether acting as a Lender or Participant) is responsible for assuring its own compliance with the Flood Laws.

Section 12.19No Advisory or Fiduciary Responsibility.  In connection with all aspects of any transaction contemplated herein, the Borrower acknowledges and agrees that: (i) this Agreement and any transaction contemplated herein constitute an arm’s-length commercial transaction between the Borrower and its affiliates, on the one hand, and the Secured Parties, on the other hand, and the Borrower is capable of evaluating and understanding and understand and accept the terms, risks and conditions of this Agreement and such transaction, (ii) each Secured Party is and has been acting solely as a principal and not as a financial advisor, agent or fiduciary, for the Borrower or any of the Borrower’s affiliates, equityholders, directors, officers, employees, creditors or any other party, (iii) no Secured Party has assumed or will assume an advisory, agency or fiduciary responsibility in the Borrower’s or any Borrower’s affiliate’s favor with respect to this Agreement or transaction contemplated herein or the process leading thereto (irrespective of whether any Secured Party has advised or is currently advising the Borrower or such affiliate on other matters) and no Secured Party has any obligation to the Borrower or any affiliate of the Borrower with respect to this Agreement or any transaction contemplated herein except those obligations expressly set forth in this Agreement, (iv) any of the Secured Parties may be engaged in a broad range of transactions that involve interests that differ from the Borrower’s and those of any Affiliate of the Borrower and no Secured Party shall have any obligation to disclose any of such interests, and (v) no Secured Party has provided any legal, accounting, regulatory or tax advice with respect to this Agreement or any transaction contemplated herein and the Borrower has consulted with its own legal, accounting, regulatory and tax advisors to the extent the Borrower has deemed appropriate.  The Borrower hereby waives and releases, to the fullest extent permitted by law, any claims that the Borrower may have against any Secured Party with respect to any breach or alleged breach of agency or fiduciary duty.

Section 12.20INTEGRATION.  THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES

[SIGNATURES BEGIN NEXT PAGE]

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Name of Lender	Applicable Percentage		Maximum Credit Amount
Wells Fargo Bank, N.A.	16.0000000	%	$	160,000,000.00
MUFG Union Bank, N.A.	11.2000000	%	$	112,000,000.00
Credit Agricole Corporate and Investment Bank	11.2000000	%	$	112,000,000.00
Capital One, National Association	11.2000000	%	$	112,000,000.00
JPMorgan Chase Bank, N.A.	11.2000000	%	$	112,000,000.00
Toronto Dominion (New York) LLC	8.0000000	%	$	80,000,000.00
Comerica Bank	8.0000000	%	$	80,000,000.00
SunTrust Bank	8.0000000	%	$	80,000,000.00
BOKF, NA dba Bank of Texas	4.8000000	%	$	48,000,000.00
Citibank, N.A.	3.6000000	%	$	36,000,000.00
Barclays Bank PLC	3.6000000	%	$	36,000,000.00
IBERIABANK	3.2000000	%	$	32,000,000.00
TOTAL	100.0000000	%	$	1,000,000,000.00

EXHIBIT I

FORMS OF U.S. TAX COMPLIANCE CERTIFICATES

EXHIBIT I-1

[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of December 31, 2009 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, JONES ENERGY, INC., a Delaware corporation, each of the Lenders from time to time party thereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent.

Pursuant to the provisions of Section 5.03(e) of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with a certificate of its non-U.S. Person status on IRS Form W-8BEN or IRS Form W-8BEN-E.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:
Date:            , 20[  ]

EXHIBIT I-2

[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of December 31, 2009 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, JONES ENERGY, INC., a Delaware corporation, each of the Lenders from time to time party thereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent.

Pursuant to the provisions of Section 5.03(e) of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code, and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN or IRS Form W-8BEN-E.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:
Date:            , 20[  ]

EXHIBIT I-3

[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of December 31, 2009 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, JONES ENERGY, INC., a Delaware corporation, each of the Lenders from time to time party thereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent.

Pursuant to the provisions of Section 5.03(e) of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect to such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its direct or indirect partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or IRS Form W-8BEN-E or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN or IRS Form W-8BEN-E from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:
Date:            , 20[  ]

EXHIBIT I-4

[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of December 31, 2009 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, JONES ENERGY, INC., a Delaware corporation, each of the Lenders from time to time party thereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent.

Pursuant to the provisions of Section 5.03(e) of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Loan(s) (as well as any Note(s) evidencing such Loan(s)), (iii) with respect to the extension of credit pursuant to the Credit Agreement or any other Loan Document, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with IRS Form W-8IMY accompanied by one of the following forms from each of its direct or indirect partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or IRS Form W-8BEN-E or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN IRS Form W-8BEN-E from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:
Date:            , 20[  ]

EX-10.34

Exhibit 10.34

AMENDED AND RESTATED

FIRM CRUDE OIL GATHERING AND
TRANSPORTATION AGREEMENT

October 23, 2015

MONARCH OIL PIPELINE, LLC

“GATHERER”

AND

JONES ENERGY, LLC

“SHIPPER”

AMENDED AND RESTATED FIRM CRUDE OIL

GATHERING AND TRANSPORTATION AGREEMENT

This Amended and Restated Firm Crude Oil Gathering and Transportation Agreement (“Agreement”) is made and entered into this 23rd day of October, 2015 (“Effective Date”), by and between Monarch Oil Pipeline, LLC, a Delaware limited liability company (“Gatherer”) and Jones Energy, LLC, a Texas limited liability company (“Shipper”).  Gatherer and Shipper are sometimes referred to herein individually as a “Party” and collectively as, the “Parties.”

RECITALS

1.Shipper and Gatherer have entered into the Firm Crude Oil Gathering and Transportation Agreement, dated as of September 26, 2014 (the “Original Agreement”).

2.Shipper holds certain oil and gas leases located in Lipscomb and Hemphill Counties, Texas (as described on Exhibit A), and has Crude Oil production therefrom that it desires to have gathered by pipeline or received at truck unloading terminals by Gatherer.

3.Shipper desires Gatherer to design, newly construct, own, maintain and operate various Crude Oil pipelines, automated truck unloading facilities, and other related facilities to be located in Lipscomb and Hemphill Counties, Texas for the purpose of receiving for the gathering and further handling on a firm basis of Shipper’s Crude Oil located in the South Lipscomb and Hemphill Areas.  The Parties have executed a Letter of Intent (“LOI”) dated April 10, 2014, whereby Shipper, in order to provide Gatherer and/or its Affiliates an incentive to build the facilities, agreed to dedicate Crude Oil production to Gatherer for pipeline gathering or truck transportation from the AOD, with such Dedication and AOD defined below in this Agreement.  Further, Shipper has the right to deliver hereunder Shipper’s Crude Oil production by truck receipts.  The total acreage dedicated to Gatherer and/or its affiliates is at least 30,000 acres for a term of ten (10) years.  Therefore, Shipper hereby agrees to serve as the Anchor Shipper so as to incent and enable Gatherer to invest the capital and resources in order commence the design, construction and operation of a new Crude Oil gathering pipeline, truck unloading facilities, and related facilities as set forth in the LOI.

4.The Parties desire to amend and restate the Original Agreement in its entirety to read as set forth below.

AGREEMENT

In consideration of the mutual covenants, promises and agreements in this Agreement and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties hereto, intending to be legally bound, do hereby amend and restate the Original Agreement in its entirety to read as follows:

ARTICLE I
DEFINITIONS

1.1The following capitalized terms used in this Agreement and the attached exhibits and schedules shall have the meaning set forth below:

“Actual Shipments” means the volumes of Crude Oil that originate at the Central Receipt Points (CRPs) and are ultimately delivered to the Delivery Point(s) for the account of Shipper.

“Affiliate” means any Person, corporation, partnership, limited partnership, limited liability company, or other legal entity, whether of a similar or dissimilar nature, which (i) controls, either directly or indirectly, a Party, or (ii) is controlled, either directly or indirectly, by such Party, or (iii) is controlled, either directly or indirectly, by a Person or entity which directly or indirectly controls such Party.  As used in this definition, “control” means the ownership of (or the right to exercise or direct) fifty percent (50%) or more of the voting rights in the appointment of directors of such entity, or fifty percent (50%) or more of the interests in such entity.

“Agreement” has the meaning set forth in the initial paragraph.

“Anchor Shipper” means any Person that agrees to be contractually bound to be the initial or first shipper of Crude Oil on the Facilities upon the completion of the construction or modification of the Facilities

“API Gravity” or “Gravity” means Gravity determined in accordance with the ASTM International (formerly known as the American Society for Testing and Materials) (“ASTM”) Designation D-287-82 or the latest revision thereof

“Applicable Law” means with respect to any Person, property or matter, any of the following applicable thereto: any statute, law, regulation, ordinance, rule, judgment, rule of common law, order, decree, governmental approval, concession, grant, franchise, license, agreement, directive, ruling, guideline, policy, requirement or other governmental restriction or any similar form of decision of, or determination by, or any interpretation, construction or administration of any of the foregoing, by any Governmental Authority, in each case as amended.

“Area of Dedication” or “AOD” means the areas depicted on Exhibit B and described as: (i) “South Lipscomb” and located in Lipscomb County, Texas and a two-mile radius surrounding the South Lipscomb Area, (ii) “Hemphill” and located in Hemphill County, Texas, and a two-mile radius surrounding the Hemphill Area, and (iii) any part of the Area of Mutual Interest added to the Area of Dedication pursuant to Section 3.1.1; in each case, from which Shipper’s Crude Oil is dedicated to this Agreement.  Exhibit B shall be amended from time to time as agreed by the Parties.

“Area of Mutual Interest” or “AMI” means the areas depicted on Exhibit B.

“ASME” means American Society of Mechanical Engineers.

“ASTM” means ASTM International, formerly known as the American Society for Testing and Materials.

“Barrel” or “bbl” means forty-two (42) gallons of 231 cubic inches per gallon at 60 degrees Fahrenheit (60° F).

“BPD” means barrels per day.

“BS&W” means basic sediment, water and other impurities.

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“Business Day” means any day other than a Saturday, Sunday or other day on which banks in the State of Texas are permitted or required to close.

“Casey Station” has the meaning set forth in Section 2.1.2.

“Central Receipt Points” or “CRPs” means the inlet flange of Gatherer’s facilities at the receipt points located along the Gathering System for the purpose of receiving Shipper’s Crude Oil, Casey Station, Osborn Station, and any other points mutually agreed upon in the future at which Gatherer will receive Shipper’s Crude Oil.  Prior to the Commencement Date, each CRP shall be equipped with (i) automated communication equipment to allow for remote monitoring and control of Gathering System pumps at each such location and (ii) a LACT Unit. The CRPs are described on Exhibit C-1.

“Commencement Date” shall be the Facilities’ in-service date which shall be the first Day of the Month following the date Gatherer notifies Shipper that Gatherer has obtained all required operating permits and/or necessary regulatory approvals, that the required amounts of line and tank fill have been delivered by Shipper to Gatherer in accordance with Section 4.7 titled Line Fill and Tank Fill, and that the Facilities are operational to the extent necessary to commence commercial service with respect to the receipt, gathering, transportation, storage, handling and delivery of Crude Oil under this Agreement.

“Connection Timing Commitment” has the meaning set forth in Section 4.4.

“Crude Oil” means naturally occurring, unrefined petroleum product composed of hydrocarbon deposits of varying grades.

“Day” means a period of twenty-four (24) consecutive hours commencing at 00:00:01 Central Time.

“Dedicated Firm Shipper” means a Shipper that has (a) committed all Crude Oil production from at least 30,000 acres for a term of at least 10 years; and (b) entered into an Agreement with Gatherer prior to the Commencement Date.

“Dedication” means Shipper’s dedication, subject to Article III, to Monarch and/or its Affiliates, for the Term except and to the extent released hereunder, of all of Shipper’s recoverable Crude Oil or Shipper’s Affiliate’s recoverable Crude Oil produced from oil and gas wells located within the Area of Dedication in which Shipper or its Affiliates now or hereafter owns, controls, acquires, and has the right to sell, market (as such marketing rights may change from time to time), or otherwise dispose of and that is not subject to a Prior Dedication as of the Effective Date (or, for subsequently acquired interests within the Area of Dedication, that is not subject to a Prior Dedication as of the date of acquisition).  Shipper agrees that the entirety of Shipper’s Crude Oil subject to Shipper’s Dedication shall be delivered by Shipper to Monarch and/or its Affiliates either at the CRP(s) or at the automated truck unloading stations at the Casey Station where Monarch and/or its Affiliates shall receive the Crude Oil for its transportation in accordance with this Agreement.

“Delivery Point(s)” means the outlet flange of Gatherer’s facilities upstream of the interconnect with Valero at or near the Valero Piper Station in Lipscomb County, Texas, the outlet flange of Gatherer’s truck loading and unloading facilities at Osborn Station, and the outlet flange of Gatherer’s truck loading and unloading facilities at Casey Station and any other points mutually agreed upon in the

3

future at which Gatherer will redeliver Shipper’s Crude Oil.  The Delivery Point(s) are described on Exhibit C-1.

“Disclosing Party” has the meaning set forth in Section 14.1.

“Effective Date” has the meaning set forth in the initial paragraph.

“Excess Volume” has the meaning set forth in Section 3.3.1.

“Expedited Temporary Release” has the meaning set forth in Section 3.1.3(a)ii.

“Expedited Temporary Release Period” has the meaning set forth in Section 3.1.3(a)ii.

“Extended Force Majeure Event” has the meaning set forth in Section 3.1.3(b).

“Facilities” means Gatherer’s facilities constituting the Gathering System, Casey Station, the Osborn Station, and Gatherer’s interconnection facilities with Valero’s facilities at or near the Valero Piper Station in Lipscomb County, Texas.

“Facilities Loss Allowance” shall mean the Facilities’ actual losses due to evaporation, measurement, or other losses in transit.

“Fee(s)” means, collectively, the Gathering Fee, the Priority Capacity Rate, the Treating Fee and Unloading and Transportation Fee, as applicable.

“Force Majeure” has the meaning set forth in Section 11.1.

“Gatherer” has the meaning set forth in the initial paragraph.

“Gathering Fee” has the meaning set forth in Section 5.1.1.

“Gathering System” has the meaning set forth in Section 2.1.1(a).

“Governmental Authority” means any court, government (federal, tribal, state, local, or foreign), department, political subdivision, commission, board, bureau, agency, official, or other regulatory, administrative, or governmental authority.

“Governmental Authorizations” means any authorization, approval or permit from any national, regional, state, local or municipal government, or any political subdivision, agency, commission or authority thereof (including any maritime authorities, port authority or any quasi-governmental agency) having jurisdiction over a Party or its Affiliates, the Facilities or any of the activities contemplated by this Agreement pursuant to this Agreement.

“Hemphill Area” means the lands identified on Exhibit B as “Hemphill”.

“Initial CRP(s)” means the 120 CRPs identified in Exhibit C-1-A; provided that, for all purposes herein, each CRP identified on Exhibit C-1-A shall become an Initial CRP on or before the deadline date applicable to such CRP, as such date is set forth in the heading row of the table in which such CRP is identified on Exhibit C-1-A.

4

“Interruption” and “Curtailment” have the meaning set forth in Section 4.8.1.

“LACT Unit” means an oil industry standard lease automated custody transfer unit comprised of a Coriolis mass measurement meter and BS&W monitor, as well as other necessary controls.

“Line Fill” and “Tank Fill” means the static quantity of Crude Oil needed to occupy the physical space within the Facilities required for Facilities operations.

“LOI” has the meaning set forth in the second recital.

“Losses” means all losses, liabilities, damages, claims, demands, fines, penalties, costs, or expenses, including reasonable attorneys’ fees and court costs.

“Month” means a calendar month beginning at 12:01 am on the first day of the calendar month and ending at 12:01 am on the first day of the next calendar month.

“Notice(s)” has the meaning set forth in Section 13.1.

“Osborn Station” has the meaning set forth in Section 2.1.3.

“Party” or “Parties” has the meaning set forth in the initial paragraph.

“Person” shall be broadly interpreted to include, without limitation, any corporation, company, partnership, trust, governmental authority or individual

“Primary Term” has the meaning set forth in Section 6.1.

“Priority Capacity” has the meaning set forth in Section 4.8.3.

“Priority Capacity Rate” has the meaning set forth in Section 5.1.2.

“Prior Dedication” has the meaning set forth in Section 3.1.2.

“Proration” has the meaning set forth in Gatherer’s Rules and Regulations.

“Prorationed Capacity” has the meaning set forth in Section 4.8.2.

“Quality Specifications” has the meaning set forth in Section 7.1.1.

“Receiving Facilities” has the meaning set forth in Section 7.1.1.

“RFP” means Shipper’s Updated Request for Proposal date February 13, 2014.

“RRC” means the Railroad Commission of Texas, or any successor agency.

“Rules and Regulations” has the meaning set forth in Section 12.2.

“Secondary Term” has the meaning set forth in 6.1.

“Shipper” includes the Party that executes the Agreement, and that Party’s heirs, successors, and assignees.

5

“Shipper’s Crude Oil” means the Crude Oil produced from oil and gas wells in which Shipper or its Affiliates owns or controls an interest and has the right to market.

“South Lipscomb Area” means the lands identified on Exhibit B as “South Lipscomb” and located in Lipscomb and Hemphill Counties, Texas.

“Subsequently Acquired Crude Oil” has the meaning set forth in Section 3.1.1(a).

“Temporary Release” has the meaning set forth in Section 3.1.3(a).

“Term” has the meaning set forth in Section 6.1.

“Third Party” means any Person not a Party or an Affiliate of a Party to this Agreement.

“Treating Fee” has the meaning set forth in Section 7.1(a)(3).

“Uneconomic” has the meaning set forth in Section 6.2.1.

“Unloading and Transportation Fee” has the meaning set forth in Section 5.1.1.

“Year” or “year” means any period consisting of 365 consecutive days, commencing and ending at 7:00 a.m., prevailing Central Time; provided that any year which contains the date of February 29 will consist of 366 consecutive days.

1.2Rules of Interpretation.

1.2.1Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant hereto.

1.2.2As used herein, and in any certificate or other document made or delivered pursuant hereto, (i) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (ii) the word “incur” shall be construed to mean incur, create, issue, assume, become liable in respect of or suffer to exist (and the words “incurred” and “incurrence” shall have correlative meanings), and (iii) references to agreements or other contracts shall, unless otherwise specified, be deemed to refer to such agreements or contracts as amended, supplemented, restated or otherwise modified from time to time.

1.2.3The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.

1.2.4The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

6

ARTICLE II
CONSTRUCTION AND MAINTENANCE OF FACILITIES

2.1Construction of the Facilities.  Upon the Effective Date and subject to obtaining all required permits, consents, regulatory approval and rights-of-way, Gatherer will at its sole cost and expense engage in construction of the Facilities as follows:

2.1.1Gathering System.

(a)Pipeline.  Gatherer will design, construct, own, operate and maintain crude oil pipelines (“Gathering System”) and related facilities in Lipscomb and Hemphill Counties, Texas to enable Gatherer to gather Shipper’s Crude Oil produced from the South Lipscomb Area at the CRPs to the Casey Station.  Gatherer will design, construct, own, operate and maintain a 4” crude oil pipeline to receive Shipper’s Crude Oil at the Casey Station and deliver it to the Delivery Point(s).  A map of the Gathering System is attached hereto as Exhibit C-1.

(b)Central Receipt Points.  Gatherer shall design, construct, own, operate and maintain 120 CRPs “Initial CRPs” and any additional CRPs as required under the terms of the Agreement, the exact locations of which shall be determined by Shipper.  Shipper agrees to cause 480-volt electricity to be available at each CRP location. The CRPs are depicted on Exhibit C-1 and the flow diagram of a typical CRP installation is attached hereto as Exhibit C-2.

2.1.2Casey Station.  Gatherer will design, construct, own, operate and maintain a facility located at the terminus of the Gathering System in Section 161 in Lipscomb County, Texas (“Casey Station”), consisting of inlet meters (measuring all Crude Oil entering the Casey Station from the Gathering System), a minimum of four automated truck loading and unloading facilities, a minimum of 10,000 BPD of Crude Oil tank storage, vapor recovery equipment, and subject to the Parties mutually agreeing to a fee, a crude oil heater to be utilized as necessary in the event Crude Oil is delivered that does not meet the specifications herein.  The Casey Station flow diagram is attached hereto as Exhibit C-3.

2.1.3Osborn Station.  Gatherer will design, construct, own, operate and maintain a facility located at the terminus of the Gatherer’s Gathering System at or near the Valero Piper Station in Lipscomb County, Texas (“Osborn Station”), consisting of inlet meters (measuring all Crude Oil delivered to Valero Pipeline at the Valero Piper Station from the Gathering System), a minimum of two automated truck loading and unloading facilities with LACT measurement units, a minimum of 3,000 BPD of Crude Oil tank storage, vapor recovery equipment, and subject to the Parties mutually agreeing to a fee, a crude oil heater to be utilized as necessary in the event Crude Oil is delivered that does not meet the specifications herein. The Osborn Station flow diagram is attached hereto as Exhibit C-4.

2.2Maintenance and Other Operations.

2.2.1Gatherer shall have the exclusive responsibility, control and management over the operation, maintenance and repair of the Facilities.  Gatherer shall perform its obligations

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under this Agreement in a good and workmanlike manner, in its judgment as a reasonably prudent operator, and in conformity with the practices in the industry and particular circumstances operating in and around the South Lipscomb Area and Hemphill Area in Texas.

2.2.2Gatherer may interrupt its performance for a reasonable period of time for the purpose of making necessary or desirable inspections, alterations, and repairs (“Maintenance”) and Gatherer shall give Shipper reasonable Notice of its intention to suspend its performance, except in cases of emergency where such Notice is impracticable or in cases where the operations of Shipper will not be affected.  Gatherer shall endeavor to arrange such interruptions so as to inconvenience Shipper as little as possible.

2.2.3During any event(s) of Maintenance affecting Gatherer’s ability to transport Shipper’s Dedication for a period in excess of seven (7) consecutive Days, such Maintenance shall be deemed an Interruption and Curtailment event and Shipper shall be released from its obligation hereunder to deliver the Crude Oil Gatherer at the Receipt Point(s) pursuant to Section 3.1.3.

2.3Compliance with Laws — Construction.  Gatherer represents and warrants that the Facilities have been or will be constructed in a good and workmanlike manner and in compliance with all federal, state, tribal and local laws, ordinances, rules, regulations and orders of governmental authorities with jurisdiction over the Parties and/or Facilities, including compliance with Department of Transportation regulations regarding pipeline safety standards found at CFR Title 49 — Transportation, Subchapter D — Pipeline Safety, Part 195 — Transportation of hazardous Liquids by Pipeline.

2.4Sale of Gathering System Prior to Completion.  If Gatherer desires to sell the Gathering System to an unaffiliated third party prior to its completion, including through a change of control (excepting a public offering of equity or other ownership by Gatherer), Gatherer will require the new Gatherer of the Gathering System to assume Gatherer’s obligations under this Agreement, the LOI and the RFP, along with any agreed-to system plans and designs.

2.5Easements Rights-of-Way, And Third Party Well Connects.

2.5.1Easements and Rights-of-Way.  To the full extent of its rights to do so, Shipper hereby assigns and grants to Gatherer the necessary easements and rights-of-way, including surface locations, on and across the lands and leases associated with the Dedication hereunder for the purpose of installing, using, inspecting, repairing, operating, replacing, and removing Gatherer’s pipelines, meters, and other equipment used or useful in the performance of this Agreement.  Any property of Gatherer placed in or upon such lands shall remain the personal property of Gatherer, subject to removal of it at any time for any reason within a reasonable time after the termination of this Agreement.  Subject to any mineral or surface lease, or any other contractual obligations, Gatherer shall enjoy the rights of ingress and egress across the land and leases of Shipper for the purposes herein.

2.5.2Third Party Well Connects.  Gatherer shall have the right to connect Third Party well(s) to any lateral pipeline downstream of the CRPs, that Gatherer installs originally to connect one of Shipper’s well(s) hereunder and to commingle Third Party Crude Oil that meets

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the quality and other delivery requirements applicable to Shipper’s Crude Oil hereunder with Shipper’s Crude Oil in such pipeline.  Prior to connecting a Third Party well to any pipeline lateral installed originally to connect one of Shipper’s Wells, Gatherer shall determine the capacity of such pipeline lateral and will refrain from connecting the Third Party well to such lateral if the connection of the Crude Oil from such Third Party will cause a violation of a term or condition of this Agreement.

2.6Intrastate Common Carrier.  Gatherer will operate the Gathering System to the extent it provides service in intrastate commerce, as an intrastate common carrier oil pipeline as defined under Texas law.

2.7In Service Date.  Gatherer shall use commercially reasonable efforts to place the Facilities in service by November 1, 2015.  If the Gathering System is not in service by November 1, 2015, then Shipper shall have the right to contract for alternative transportation of Shipper’s Crude Oil for consecutive ninety (90) Day periods until such time as the Facilities are in service, provided that if the Facilities go in service during one such ninety (90) Day period, Shipper shall have no obligation to transport Shipper’s Crude Oil on the Facilities until the expiration of that ninety (90) Day period.

ARTICLE III
DEDICATION

3.1Shipper’s Dedication.  Shipper’s Crude Oil is dedicated hereunder as set forth in the definition of the term “Dedication” in Article I, Section 1.1, subject to the terms of this Article III.

3.1.1Addition to Dedication.

(a)Subsequently Acquired Crude Oil.  If, after the Effective Date, Shipper acquires any right, title or interest in Crude Oil that is to be produced from any completed or future well in the Area of Mutual Interest, Shipper shall promptly give Gatherer written Notice identifying, for any and all such wells: Shipper’s right, title or interest in such Crude Oil (“Subsequently Acquired Crude Oil”); the location of the well; the well’s historical production or estimated future production; the estimated completion date for the well; and whether the Subsequently Acquired Crude Oil was acquired by Shipper subject to Prior Dedication.  If the Subsequently Acquired Crude Oil is subject to Prior Dedication, Shipper shall give Gatherer an additional written Notice no later than thirty (30) Days preceding the expiration or termination of the term of the Prior Dedication.

i.Beginning on the same Day Gatherer receives Notice of the Subsequently Acquired Crude Oil (or, for Subsequently Acquired Crude Oil subject to Prior Dedication, on the Day Gatherer receives the additional Notice preceding the expiration or termination of the term of the Prior Dedication), and for a period of thirty (30) Days thereafter, Gatherer shall have the option to include such Subsequently Acquired

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Crude Oil to this Agreement for Pipeline Gathering Services; provided, however, that Gatherer shall have no right to exercise such option if either (A) the Gathering System does not have sufficient capacity available to provide firm service for the estimated future production of Crude Oil from the applicable well or (B) Shipper does not have an available market at the Delivery Point(s) for all such estimated future production of Crude Oil from the applicable well, provided that Shipper has exercised commercially reasonable efforts to obtain a market at the Delivery Point(s).

ii.If Gatherer has the right to exercise such option, Gatherer must exercise such option by providing Shipper written Notice within the thirty (30) Day period set forth in Section 3.1.1(a)i.  In Gather’s Notice, Gatherer must provide to Shipper the date on which Gatherer expects to connect to the Gathering System the CRP(s) for such Subsequently Acquired Crude Oil.

iii.If Gatherer exercises such option under this Section 3.1.1(a), then, effective immediately, this Agreement shall be deemed amended to include (A) to the Dedication, such Subsequently Acquired Crude Oil, (B) to the AOD, the lands subject to the leases (or other similar rights) in respect of such Subsequently Acquired Crude Oil, (C) the CRP(s) at which the Subsequently Acquired Crude Oil will be received by Gatherer, and (D) the Delivery Point(s) at which the Subsequently Acquired Crude Oil will be delivered by Gatherer.

iv.Any wells added to the Dedication pursuant to this Section 3.1.1 will be subject to the Connection Timing Commitment as defined in Section 4.4.

v.If the option expires or Gatherer declines to exercise the option as set forth in this Section 3.1.1(a) such Subsequently Acquired Crude Oil shall be permanently released from this Agreement and the lands subject to the lease(s) (or other similar rights) in respect of such Subsequently Acquired Crude Oil shall be removed and permanently excluded from the AMI and/or AOD, as applicable; provided that such release, removal and exclusion in respect of such Subsequently Acquired Crude Oil pursuant to this Section 3.1.1(a)v. does not affect either Party’s rights in respect of any other Subsequently Acquired Crude Oil.

(b)Future Expansions.  Subject to Section 3.1.1(a), the AOD shall at all times include all lands within two (2) miles of any part of the Gathering System except as otherwise excluded pursuant to Section 3.1.1.  If Gatherer at any time after the Effective Date expands the Gathering System, then, beginning on the in-service date of such expansion, the AOD shall be increased to include all lands within

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two (2) miles of any part of such expansion and this Agreement shall be deemed amended to reflect the increased AOD.

3.1.2       Exclusion from Dedication.

(a)           The Dedication does not include any Crude Oil that has previously been dedicated to another pipeline or market prior to the Effective Date (or in the case of subsequently acquired interests, prior to the date of such acquisition) (the “Prior Dedication”).  Shipper shall not extend marketing or transportation agreements governing Crude Oil subject to a Prior Dedication(s) beyond the end of the longest primary contract term associated with the transportation and/or marketing of that particular Crude Oil.  Upon termination of such agreements, all Crude Oil subject to the Prior Dedication(s) shall be deemed part of Shipper’s Dedication hereunder for the remaining Term of this Agreement.

(b)           If Shipper transfers any right, title, or interest in the Dedication, such transfer shall be made subject to this Agreement and any such transfer shall not impair the Dedication herein to Gatherer.  Shipper shall notify Gatherer of any such transfer within ten (10) Business Days of the effective date thereof.  Shipper shall notify in writing any transferee that such acreage remains dedicated to Gatherer pursuant to this Agreement and Shipper shall ensure that any such transfer is accompanied with appropriate contractual language requiring the transferee to deliver Crude Oil subject to the Dedication to Gatherer during the Term of and in accordance with this Agreement.  Any such transfer or Shipper’s failure to notify Gatherer thereof shall not impair Gatherer’s rights under this Agreement as against Shipper; provided that Gatherer shall release and waive any rights under this Agreement it may have against Shipper if and to the extent the transferee enters into an agreement with Gatherer on substantially the same terms as those provided herein in respect of the transferred rights, title or interest in Crude Oil subject to the Dedication.

(c)           If Shipper transfers any right, title, or interest in some, but not all of the Dedication, in addition to the requirements set forth above, any right, title, or interest retained by Shipper shall remain subject to this Agreement and the Dedication, and Shipper’s fees under Article V, shall not be affected by the transfer.  All of Shipper’s right, title, or interest in Crude Oil subject to the Dedication will continue to be subject to the Dedication and the fees in Article V will remain unchanged.

(d)           In addition to the audit rights of the Parties in Section 9.4, on thirty (30) Days prior written Notice, Gatherer shall have the right at its expense, at reasonable times during business hours on a Business Day, to audit the books and records of Shipper to the extent necessary to verify the accuracy of any statement or representation of Shipper related to Shipper’s Dedication, Prior Dedications or other prior obligations.

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3.1.3       Interruption.

(a)           Short-Term Interruption — Release from Dedication.  During any event(s) of Force Majeure as defined in Article XI herein, Prorationed Capacity, or Interruption and Curtailment affecting Gatherer’s ability to accept Shipper’s Dedication for a period in excess of seven (7) consecutive Days, Shipper shall have a temporary release from this Dedication, but only for those Barrels: (1) not accepted by the Gatherer in its Facilities; or (2) intended for delivery to the CRPs affected by such Force Majeure, Prorationed Capacity or Interruption and Curtailment (“Temporary Release”); except that, if the cause of any event(s) of Force Majeure, Prorationed Capacity, or Interruption and Curtailment is due solely to the individual or collective gross negligence of Shipper and/or any Affiliate, agent, or subcontractor thereof, Shipper shall be granted a Temporary Release, but shall be required to pay Gatherer the fees under Section 5.1.1 as though the Barrels subject to the Temporary Release constituted Actual Shipments over and through the Facilities, a notarized accounting of which shall be provided to Gatherer within fifteen (15) Days of Shipper resuming deliveries to the Facilities following the end of such Temporary Release.

i.              For the duration of any such Temporary Release, Shipper will be free to dispose of released Crude Oil volumes under other arrangements in Shipper’s sole discretion, provided that Shipper shall make commercially reasonable efforts to sell Shipper’s released Crude Oil volumes to the owner of the pipeline(s) immediately downstream of the Delivery Point(s), and/or its affiliates.  To the extent Shipper was able to sell Shipper’s released Crude Oil volumes to the owner of the pipeline(s) immediately downstream of the Delivery Point(s), and/or its affiliates, Shipper shall resume deliveries of released Crude Oil volumes to the Facilities no later than the third (3rd) Day following delivery of Notice by Gatherer stating that the Force Majeure, Prorationed Capacity, or Interruption and Curtailment has ended and Gatherer is able to accept delivery of all such released volumes.  For all other temporarily released volumes, Shipper’s Temporary Release from the Dedication shall end, and Shipper shall resume deliveries of released Crude Oil volumes to the Facilities, no later than the first (1st) Day of the fourth (4th) month following delivery of Notice by Gatherer stating that the Force Majeure, Prorationed Capacity or Interruption and Curtailment has ended and Gatherer is able to accept delivery of all such released volumes of Shipper’s Crude Oil.

ii.             Notwithstanding the requirements above, Shipper’s Temporary Release shall commence prior to the expiration of the seven (7) consecutive Day period if waiting the full seven (7) Days will cause Shipper to shut in production wells within the AOD and expediting the release is the only way to avoid the shut in (“Expedited Temporary Release”).  The Expedited Temporary Release period shall last only until the expiration of the seven (7) Day waiting period set forth above (“Expedited Temporary Release Period”).  Shipper may sell its Crude Oil at the affected CRP(s) or at the Casey Station to third-parties through the end the

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Expedited Temporary Release period only.  The provisions in Section 3.1.3(a)  and 3.1.3(a)(i) above, shall not apply until the Expedited Temporary Release Period has expired.  Shipper shall provide Notice to Monarch prior to releasing Shipper’s Crude Oil in an Expedited Temporary Release.  The Notice shall state that the release meets the criteria of this Sub-Section for an Expedited Temporary Release.

(b)           Long-Term Interruption — Release from Dedication.  Within twenty-one (21) Days of any event(s) of Force Majeure or Interruption and Curtailment affecting Gatherer’s ability to accept all or part of the Crude Oil volumes subject to Shipper’s Dedication, Gatherer shall provide Shipper with Notice to the extent Gatherer anticipates such event(s) will last longer than one hundred and eighty (180) Days (the “Extended Force Majeure Event”).  Gatherer’s notification shall include a good faith estimate of the length of the Extended Force Majeure Event and when Gatherer anticipates it again will be able to accept such Crude Oil volumes subject to Shipper’s Dedication.  Shipper and Gatherer will work together in good faith to find alternative gathering and/or transportation services for such Crude Oil volumes subject to Shipper’s Dedication and affected by the Extended Force Majeure Event.  The term of any such alternative gathering and/or transportation service agreement must end no later than the first (1st) Day of the second (2nd) full Month following Gatherer’s notification’s estimated end date for the Extended Force Majeure Event.

3.2          Shipper’s Reservations.  Shipper reserves the following rights:  (i) to operate the wells producing from the AOD as a reasonably prudent operator; (ii) to operate separation and tankage facilities on the well sites in the AOD; (iii) to pool, communitize, or unitize Shipper’s interests in the AOD; (iv) to use Crude Oil for lease operations (excluding any type of major secondary or tertiary recovery projects); and (v) to distribute Crude Oil in-kind to various Third Parties as required by contractual obligations of Shipper in effect prior to the date hereof (or, for any later acquired interests, prior to the date of the acquisition), including lessors and royalty owners as required by the applicable provisions of any such oil and gas lease.

3.3          Rights to Unutilized Capacity.

3.3.1       Subject to available capacity, Shipper shall have the right during each Month of the Term, but not the obligation, to ship Shipper’s Crude Oil in excess of 5,000 BPD (“Excess Volume”) at the Gathering Fee set forth in Section 5.1.1.  Gatherer agrees to transport such Excess Volume subject to available capacity and the provisions set forth in Gatherer’s Tariff.

3.3.2       Shipper agrees that, to the extent it does not utilize its capacity in any Month, Gatherer may utilize such unused capacity for the provision of services to other shippers without impacting the payment or Dedication obligations of Shipper under this Agreement.

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ARTICLE IV
GATHERING SERVICES

4.1          Pipeline Gathering Service.  Commencing on the Commencement Date, Shipper shall deliver or cause to be delivered Shipper’s Crude Oil subject to the Dedication and connected directly to an Initial CRP or future CRP for pipeline gathering.  Gatherer shall accept delivery of such Shipper’s Crude Oil as nominated at the CRPs and shall gather such Shipper’s Crude Oil and redeliver it on a firm basis to the Delivery Point(s), net Shipper’s pro-rata share of the Facilities Loss Allowance.

4.2          Non-Pipeline/Truck Deliveries.

(a)           Commencing on the Commencement Date, Shipper shall deliver or cause to be delivered by means other than through the Gathering System Shipper’s Crude Oil from the wells listed on Exhibit C-1-B and Exhibit C-1-D to the truck facilities at the Casey Station or the Osborn Station, as applicable.  Further, Shipper has the right to deliver Shipper’s Crude Oil by truck receipts from the North Lipscomb or other areas to the truck facilities at the Casey Station or the Osborn Station, as applicable, and Gatherer shall unload and accept into its Facilities at the Casey Station or the Osborn Station, as applicable, for Shipper’s account all of such Shipper’s Crude Oil pursuant to the terms and conditions herein; provided that Gatherer shall (i) not later than one hundred twenty (120) Days after receiving written notice from Shipper therefor, connect all wells listed on Exhibit C-1-D as CRPs for gathering services hereunder in accordance with Section 4.1, and (ii) not later than five (5) Business Days after Gatherer’s receipt of the notice described in the preceding clause (i), commence the acquisition process for any and all ROWs that Gatherer reasonably believes are necessary to connect such wells within such one hundred twenty (120) Day period; and provided further that Shipper’s obligation to deliver or cause to be delivered by means other than through the Gathering System Shipper’s Crude Oil from the wells listed on Exhibit C-1-D to the truck facilities at the Casey Station or the Osborn Station, as applicable, shall cease after such wells are connected directly to a CRP for pipeline gathering and Gatherer has commenced receipts of Shipper’s Crude Oil from such wells by pipeline gathering service pursuant to Section 4.1.  Gatherer will redeliver such Shipper’s Crude Oil at the Delivery Point(s), net Shipper’s pro-rata share of the Facilities Loss Allowance.

(b)           Commencing on the Commencement Date, Gatherer shall load and receive or cause to be loaded and received by truck(s) all of Shipper’s Crude Oil produced from the wells listed on Exhibit C-1-C and Exhibit C-1-A and shall transport and deliver by truck such Shipper’s Crude Oil to the truck facilities at the Casey Station or the Osborn Station, as applicable, and Gatherer shall unload, receive and accept into its Facilities at the Casey Station or Osborn Station, as applicable, for Shipper’s account all of such Shipper’s Crude Oil pursuant to the terms and conditions herein; provided that Gatherer’s obligation to receive or cause to be received by truck(s) any of Shipper’s Crude Oil produced from a well listed on Exhibit C-1-A shall cease after such well is connected directly to a CRP for pipeline gathering and Gatherer has commenced receipts of Shipper’s Crude Oil from such well by pipeline gathering service pursuant to Section 4.1.  Gatherer will redeliver such Shipper’s Crude Oil at the Delivery Point(s), net Shipper’s pro-rata share of the Facilities Loss Allowance.  Gatherer shall bear all costs of the loading, trucking, and unloading services provided under this Section 4.2(b).

4.3          Gatherer’s Capacity Obligation.  In consideration of Shipper’s commitments herein, for the Primary Term of the Agreement, Gatherer will make available capacity of 5,000 BPD to the Valero

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Piper Station Delivery Point; provided that after the first five (5) years of the Primary Term, Gatherer will adjust the available capacity annually based on 120% of Shipper’s deliveries of Barrels of Crude Oil to the Gathering System averaged for the immediate prior calendar year; and further provided that Gatherer will only make an upward adjustment if sufficient firm capacity is available to accommodate such adjustment.

4.4          Future Newly-Drilled Well Connections.  Gatherer agrees to connect to the Gathering System any future newly-drilled wells subject to the Dedication and drilled by Shipper within the South Lipscomb Area and located within one (1) mile of the Gathering System within five (5) days of completion of any such well and prior to first production, subject to events of Force Majeure (the “Connection Timing Commitment”).  The Connection Timing Commitment will only apply to wells for which Shipper notifies Gatherer of the completion date at least forty-five (45) Days in advance of completion.  In the event that Shipper does not notify Gatherer at least forty-five (45) Days in advance of the completion date for a well, then Gatherer will commit to connecting the new well within forty-five (45) Days of receiving the Notice from Shipper.  Gatherer may, in its sole discretion, connect any future newly-drilled well subject to the Dedication and located further than one (1) mile from the Gathering System (or receive by truck Shipper’s Crude Oil produced from such well and transport and deliver such Shipper’s Crude Oil at its own expense as provided in Section 4.2(b)) in which case Exhibit C-1-A or Exhibit C-1-C, as applicable, shall be amended to include such well location; provided that Gatherer has no obligation to connect or receive from such well as set forth above in this sentence; and provided further that if Gatherer elects not to connect or receive from such well as set forth above in this sentence, then the Parties may negotiate in order to attempt to reach mutually agreeable terms to connect such well under an alternate fee structure and the Parties will amend this Agreement to memorialize any such agreement.  If the Parties are unable to mutually agree on terms to connect any future newly-drilled well located in the AOD and subject to the Dedication in accordance with the foregoing, then Shipper shall deliver Shipper’s Crude Oil produced from such well to the Casey Station or the Osborn Station, as applicable, by means other than through the Gathering System for further transportation on facilities owned and operated by Gatherer and/or its Affiliates.

4.5          Third Party Gathering.  Subject to Gatherer’s commitment to gather and accept delivery of all of Shipper’s Crude Oil as described in Section 4.1 and Section 4.2 on a firm basis, Gatherer may receive into and utilize the Facilities, including the Gathering System and truck unloading facilities, for gathering, transportation and storage of Crude Oil produced by Third Parties and, subject to Section 4.6, such Crude Oil may be commingled with Shipper’s Crude Oil.

4.6          Quality Management.  As provided in Section 4.5, Shipper acknowledges that Shipper’s Crude Oil may be commingled with other Crude Oil produced by Third Parties and that the Crude Oil delivered by Gatherer at the Delivery Point(s) will not necessarily be the identical Crude Oil delivered by Shipper to Gatherer hereunder.  If Shipper’s Crude Oil is commingled in the Facilities with Crude Oil belonging to Third Parties, then the quality Shipper’s Crude Oil and any Third Party Crude Oil gathered and transported on the Facilities will be determined and settled in accordance with Gatherer’s Quality Bank Policy, as may be amended from time to time, and attached as Exhibit F.

4.7          Line Fill and Tank Fill.  Shipper agrees to provide its pro rata share of Barrels of Crude Oil for Line Fill and Tank Fill required for operation of the Gathering System, Casey Station, Osborn

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Station and the Valero Piper Station interconnect.  Should Gatherer begin gathering or transporting Third Party Crude Oil through the Facilities, it shall provide a quarterly credit for Shipper’s account for that proportionate quantity of Crude Oil attributable to such Third Party’s pro rata share of Line Fill and Tank Fill.  At any time there is no Third Party Crude Oil gathered and transported through the Facilities, Shipper will once again provide its pro rata share of the necessary operational Line Fill and Tank Fill to the Facilities.  Crude Oil furnished for Line Fill and Tank Fill by Shipper may be withdrawn from the Gathering System only after (i) expiration or termination of this Agreement, (ii) Shipper inventory balances have been reconciled between Gatherer and Shipper, and (iii) all fees due and payable to Gatherer by Shipper have been fully and finally paid.  Gatherer shall have a reasonable period of time after satisfaction of the above in which to complete administrative and operational requirements incident to Shipper’s withdrawal of the Crude Oil.  Any losses to Line Fill and/or Tank Fill due to evaporation, measurement or other losses in transit shall be subject to allocation among all Shippers on a pro rata basis but any individual Shipper’s allocation during a Month shall never exceed 0.2% of that Shipper’s Line Fill or Tank Fill, as applicable.

4.8          Interruption, Curtailment and Proration.

4.8.1       Gatherer may “Interrupt” or “Curtail”, meaning respectively to stop or reduce transportation service to Shipper and third party shippers for such periods of time as it may reasonably require for the purpose of effecting or allowing any repairs, maintenance, replacement, upgrading or other work related to the Facilities, or upstream/downstream facilities in circumstances which do not constitute Force Majeure.  If such Interruption or Curtailment is due to a planned outage, Gatherer shall give Shipper prior notice of such Interruption or Curtailment as soon as reasonably possible.  If such Interruption or Curtailment is unforeseen, Gatherer shall give Shipper notice of such Interruption and Curtailment as soon as reasonably possible.  Gatherer shall use reasonable commercial efforts to minimize the extent and duration of any Interruption or Curtailment and the impact of such Interruption or Curtailment on the operation of the Facilities.

4.8.2      Gatherer will follow a Proration policy as set forth in the Rules and Regulations when the amount of Crude Oil nominations properly submitted by all system shippers exceeds the Gathering System’s capacity for a given Month.  The capacity available for service during the Month of allocation (design capacity less any reduction in capacity because of Interruption and Curtailment or Force Majeure as defined herein) is the “Prorationed Capacity”.

4.8.3       Gatherer will maintain ninety percent (90%) of the Prorationed Capacity for a Dedicated Firm Shipper (“Priority Capacity”).  Shipper is eligible to make a Priority Capacity election should the Facilities enter into a period of Proration.  Subject to reduced capacity (as a result of, for example, Interruption or Curtailment or Force Majeure), Priority Capacity will be available to Shipper during periods of proration.  Shipper may elect and secure Priority Capacity by paying the “Priority Capacity Rate”.  In the event that the Prorationed Capacity is less than design capacity (as a result of, for example, Interruption or Curtailment or Force Majeure), the Priority Capacity available for each Dedicated Firm Shipper will be allocated pro rata in accordance with each Dedicated Firm Shipper’s respective committed volume.

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4.8.4      A “Curtailment” or “Curtailment event” does not include Shipper’s Default or an inability to receive Crude Oil by any entity not an Affiliate of Gatherer downstream of the Delivery Point(s) for any reason.

4.9          Nominations.  All nominations by Shipper shall state the volume of Shipper’s Crude Oil, to be delivered to the Gathering System Delivery Point(s) and the trucking Delivery Point(s).  Shipper will submit Monthly nomination quantities to be delivered at the Delivery Point(s) stated in Barrels for each Month not later than the 20th Day of the Month prior to the delivery Month; provided that, when the 20th day of the Month falls on a weekend or holiday, nominations will be required on the immediately preceding workday.  Once nominated by Shipper for the Month, Shipper may change the nomination quantity at any Receipt Point or Delivery Point by submitting a revised nomination quantity no later than 11:30 a.m., Central Time, on the business day prior to the Day such revised quantity is to be effective.  Further, Shipper shall use the nomination procedure and process set forth in the applicable Rules and Regulations in the Tariff filed with the RRC, or other governmental entity having jurisdiction over the rules and terms and conditions of service of Gatherer.  If Gatherer incurs any fees, fines, penalties or other action that adversely affects Gatherer due to Shipper’s failure to nominate or comply with the requirements of the Receiving Facilities, then Gatherer has the right to suspend its performance hereunder for those deliveries of Crude Oil that are causing such fees, fines, penalties or action, and Shipper shall pay, or reimburse Gatherer for any expense it incurs plus a reasonable amount for overhead, for such fees, fines, penalties or the action.

4.10        Allocation of Deliveries.  Shipper and each Third Party shipper will have allocated to it at the Delivery Point(s) on a Monthly basis Actual Shipments based upon the total number of Barrels delivered to all CRP’s by that respective Shipper or Third Party shipper as a percentage of the total number of Barrels delivered to all CRP’s by the Shipper and all Third Party shippers, and such allocation of the Actual Shipments will be net of Shipper’s or Third Party shippers’ pro-rata share of the Facilities Loss Allowance.  Further, Shipper’s Actual Shipments will be allocated back to individual CRP’s based upon the number of Barrels delivered to each CRP as a percentage of the total number of Barrels delivered to all CRP’s by the Shipper and all Third Party shippers, net of Shipper’s pro-rata share of Facilities Loss Allowance.

4.11        Storage.  This Agreement does not govern any commercial storage services.  Gatherer has working tanks that are needed by Gatherer to transport Crude Oil, but has no other tanks and, therefore, does not have facilities for rendering, nor does it offer, a commercial storage service.  Gatherer will use its operational storage facilities, as necessary, to manage the Gathering System and Facilities to allow for the gathering and transportation of Shipper’s Crude Oil pursuant to Shipper’s confirmed nominations for transportation to the Delivery Point(s).  Gatherer will not accept for gathering or transportation any Crude Oil volumes for which Shipper has not made the necessary arrangements for shipment beyond the Delivery Point(s) or has not provided the necessary facilities for receiving said Crude Oil as it arrives at the Delivery Point(s).  Provisions for storage during transit in facilities furnished by Shipper at points on Gatherer’s system will be permitted to the extent authorized by Gatherer.

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ARTICLE V
FEES

5.1          Fees.

5.1.1       Dedicated Firm Shipper Fee:  For each Barrel of Crude Oil delivered by Shipper, a Dedicated Firm Shipper, to Gatherer hereunder, Shipper shall pay Gatherer, as applicable, either (i) a fee (“Gathering Fee”) of $2.10 per Barrel to the extent such Shipper’s Crude Oil is either (a) delivered to Gatherer at a CRP for transportation to the Delivery Point(s) on the Gathering System, (b) loaded and received by Gatherer as truck receipts at any of Shipper’s wells and trucked by Gatherer pursuant to Section 4.2(b), or (c) delivered to Gatherer as truck receipts from any well identified on Exhibit C-1-D for transportation to the Delivery Point(s) on the Gathering System, or (ii) a fee (“Unloading and Transportation Fee”) of $1.00 per Barrel to the extent such Shipper’s Crude Oil is delivered by Shipper pursuant to Section 4.2(a) (unless Section 5.1.1(i)(c) is applicable to such Shipper’s Crude Oil) to Gatherer at Gatherer’s truck Loading/Unloading Facilities at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s).

5.1.2       Priority Capacity Rate: If Shipper elects Priority Capacity under Section 4.8.3, then, for each Barrel of Crude Oil delivered by Shipper to Gatherer hereunder, Shipper shall pay Gatherer, as applicable, a fee of either (individually or together, the “Priority Capacity Rate”) (i) $2.11 per Barrel for any of Shipper’s Crude Oil that is either (a) delivered to Gatherer at a CRP for transportation to the Delivery Point(s) on the Gathering System, (b) loaded and received by Gatherer as truck receipts at any of Shipper’s wells and trucked by Gatherer pursuant to Section 4.2(b), or (c) delivered to Gatherer as truck receipts from any well identified on Exhibit C-1-D for transportation to the Delivery Point(s) on the Gathering System, or (ii) $1.01 per Barrel for any of Shipper’s Crude Oil delivered by Shipper pursuant to Section 4.2(a) (unless Section 5.1.2(i)(c) is applicable to such Shipper’s Crude Oil) to Gatherer at Gatherer’s truck Loading/Unloading Facilities at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s).

5.1.3       Treating Fee:  As defined in Section 7.1(a)(3), a Treating Fee shall be mutually agreed to by the Parties, when and if necessary.

5.2          Annual Fee Adjustment.  Gatherer shall have the right to adjust all rates and fees set forth in this Agreement on an annual basis, including without limitation the Gathering Fee, the Priority Capacity Rate, the Unloading and Transportation Fee and the Treating Fee, each July 1 in accordance with FERC indexing methodology as described in 18 C.F.R. § 342.3, subject to the following qualifications.  In a given index year (July 1 through June 30), Gatherer’s maximum annual fee adjustment shall be the lesser of (a) the generally applicable index adjustment as published by FERC for that given index year and (b) three percent (3%).  In the event that application of the generally applicable index adjustment as published by FERC for a given index year would result in a rate decrease, Gatherer shall not be required to decrease its rates by more than three percent (3%).  Any such rate adjustment shall be prorated for the first index year Gatherer is in service by multiplying (i) the lesser of the index adjustment or three percent (3%) by (ii) a fraction, the numerator of which is the number of Days between the Commencement Date and June 30 of the index year and the denominator of which is 365.  The Gathering Fee, the Priority Capacity Rate and the Unloading and Transportation Fee shall never be lower than the rate agreed to in this Agreement.

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ARTICLE VI
TERM

6.1          Term.  This Agreement shall commence on the Effective Date and continue in effect for a period of ten (10) years (“Primary Term”).  Thereafter, the Agreement shall automatically renew for consecutive one year periods (each, a “Secondary Term” and together with the Primary Term, the “Term”).  Either Party may terminate this Agreement by written Notice to the other Party one (1) year prior to expiration of the Primary Term or any Secondary Term.

6.2          Uneconomic Operation.

6.2.1       Gatherer reserves the right, on a not unduly discriminatory or preferential basis, to reject or seek renegotiation of the terms under which Gatherer shall continue the gathering of Shipper’s Crude Oil on the Facilities should Gatherer determine that gathering Shipper’s Crude Oil at any CRP becomes Uneconomic because of insufficient volume, or if all or part of Gatherer’s Facilities receiving Shipper’s Crude Oil becomes Uneconomic to operate, maintain, or repair because of the delivery of insufficient volumes of Shipper’s Crude Oil.  Gatherer has the right to deem a CRP and any associated part of the Facilities “Uneconomic” if the average BPD over a ninety (90) Day period at a particular CRP is less than twenty (20) BPD for a CRP with one production well behind such CRP and thirty (30) BPD for a CRP with more than one production well behind such CRP; provided, however, that no Initial CRP or any part of the Facilities connecting the Initial CRPs to the Delivery Point(s) as of the Commencement Date, as such Facilities and Initial CRPs are set forth on Exhibit C-1, shall ever be deemed Uneconomic during the Primary Term. In the event of a CRP or part of the Facilities being declared Uneconomic, Gatherer shall have the right to suspend receipt of Shipper’s Crude Oil at that CRP or part of the Facilities, without liability as long as such condition exists, by giving Shipper ninety (90) Days advance written Notice of such suspension.  During the ninety (90) Day Notice period, the Parties agree to meet to discuss and negotiate in good faith new terms for the applicable CRP or part of the Facilities under which Gatherer would continue to gather Shipper’s Crude Oil for transportation on the Facilities.  If the Parties are unable to reach agreement as to a remedy to such condition within thirty (30) Days of the end of the Notice period, either Shipper or Gatherer may cause the CRP(s) or part(s) of the Facilities in question and any part of the Dedication intended for delivery to such CRP(s) or part(s) of the Facilities shall be permanently released from this Agreement.

6.2.2       During any Secondary Term, in the event Gatherer declares all or part of Gatherer’s Facilities Uneconomic, Gatherer shall have the right to suspend operations of the Facilities or the affected part thereof without liability as long as such condition exists by providing Shipper with ninety (90) Days advance written Notice of the suspension.  The Parties agree to meet within fifteen (15) Days after receipt of such Notice to discuss and negotiate in good faith alternative terms to remedy such Uneconomic Facilities condition.  If the Parties are unable to reach agreement as to a remedy to such condition within thirty (30) Days of the end of the Notice period, Gatherer may elect to terminate gathering operations with respect to all of its Facilities if it has been declared Uneconomic or such part as has been declared Uneconomic and shall provide Shipper thirty (30) Days prior written Notice of its intent to terminate such

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operations.  If Gatherer terminates all or part of its gathering operations pursuant to this Sub-Section, either Shipper or Gatherer shall have the right to and may so cause the Dedication impacted by such termination to be permanently released from this Agreement.

6.2.3Notwithstanding anything to the contrary in Section 6.2.1 or Section 6.2.2, Gatherer shall have the right to take a LACT unit out of service at a particular CRP and remove such CRP from this Agreement if the average BPD over a ninety (90) Day period at such CRP is less than ten (10) BPD.  For any such LACT unit taken out of service pursuant to this Section 6.2.3, Gatherer shall cause, at Gatherer’s sole cost and expense, trucks to load and receive all of Shipper’s Crude Oil produced from the well(s) behind such CRP, transport by truck such Shipper’s Crude Oil from such well(s), and deliver such Shipper’s Crude Oil to the truck Facilities at the Casey Station or the Osborn Station, as applicable; and Gatherer shall unload, receive and accept into its Facilities at the Casey Station or Osborn Station for Shipper’s account all of such Shipper’s Crude Oil pursuant to the terms and conditions of this Agreement.  Promptly after removing any such CRP in accordance with this Section 6.2.3, Gatherer shall amend Exhibit C-1-A and Exhibit C-1-C to reflect the removal of such CRP and the addition of such well(s) to Monarch’s obligations hereunder for trucking Shipper’s Crude Oil to the Casey Station or the Osborn Station, as applicable.

ARTICLE VII
QUALITY

7.1Quality.

(a)Quality Specifications.  Shipper warrants that Shipper’s Crude Oil is of a quality acceptable to each of the receiving facilities immediately downstream of the Delivery Point(s) (“Receiving Facilities”), in its natural produced state after normal oilfield lease operations and commercially free of dirt, sediment and chemicals foreign to virgin Crude Oil, including, but not limited to, chlorinated and/or oxygenated hydrocarbons, lead and hazardous or industrial wastes.  Notwithstanding the foregoing, Gatherer shall have the right, without prejudice to any other remedy available to Gatherer, to reject any of Crude Oil that fails to meet the Quality Specifications (“out of spec”), even after delivery to Gatherer, and to discontinue accepting Shipper’s Crude Oil for so long as such conditions exist.  Any acceptance by Gatherer of out of spec Crude Oil in one instance shall not be deemed as a waiver by Gatherer to reject out of spec Crude Oil at a later time.  Shipper shall be liable for and shall indemnify Gatherer and hold it harmless against all direct costs and Losses (including loss of revenues) incurred by Gatherer for damage to Gatherer’s Facilities or Third Party Crude Oil caused by Shipper delivering Crude Oil failing to meet the Quality Specifications or for introduction of contaminates into the Gathering System, which may include costs associated with draining the Gathering System facilities, decontaminating the Gathering System facilities, and refilling it with Line Fill and associated loss of revenues.  In addition, Shipper warrants that Shipper’s Crude Oil:

(1) shall contain less than 0.4% sulfur by weight ;

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(2) shall be of an API Gravity not to exceed 60º when corrected to 60º Fahrenheit;

(3) shall not contain more than 1% by volume basic sediment and water (“BS&W”) and other impurities, or on an individual basis, water shall not be more than 0.3% by volume and basic sediment shall not be more than 0.7% by volume as determined by the average of representative samples.  Should any of Shipper’s Crude Oil fail to meet the BS&W and Gatherer has the facilities to provide treatment service for BS&W, Shipper shall pay Gatherer a fee (“Treating Fee”), as may be mutually agreed by the Parties, and Gatherer shall treat Shipper’s Crude Oil to bring it into compliance with the BS&W.

All specifications set forth in this Section 7.1 (a) are referred to as, the “Quality Specifications”.

(b)Cooperation with Connecting Carriers.  Gatherer will work with connecting carriers regarding Gatherer’s quality specifications and will advise such connecting carriers that any Crude Oil found to be a detriment to Gatherer’s System and requirements will be rejected by Gatherer and prevented from further transportation on Gatherer’s System.

7.2Specifications as to Quality Delivered.  Gatherer warrants that the commingled Crude Oil in the Gathering System common stream at the Delivery Point(s) shall not exceed an API Gravity of the lesser of (x) 47.9 or (y) the maximum API gravity requirements of the Receiving Facilities.

ARTICLE VIII
MEASUREMENT

8.1Measurement.  All measurements hereunder shall be made from by Coriolis mass measurement meters.  All measurements and tests shall be made in accordance with the latest ASTM or ASME-API (Petroleum PD Meter Code) published methods then in effect, whichever apply.  Volume and gravity shall be adjusted to 60º Fahrenheit by the use of Table 6A and 5A of the Petroleum Measurement Tables ASTM Designation D1250 in their latest revision.  Full deduction for all free water and BS&W content shall be made according to the API/ASTM Standard Method then in effect.  Either Party shall have the right to have a representative witness all gauges, tests and measurements.  Except for arithmetic errors, in the absence of the other Party’s representative, such gauges, tests and measurements shall be deemed to be correct.  If Shipper desires to use Gatherer’s measurement reports or data to satisfy Shipper’s reporting requirements to any regulatory agency, Shipper is responsible for obtaining any license, permission, or any other authorization necessary for Shipper to use such measurement, and Shipper acknowledges that it is using such reports or data solely at its own risk.

ARTICLE IX
BILLING AND PAYMENT

9.1Billing.  On or before the 15th day of the month, Gatherer shall bill Shipper each month for the Fees for gathering and unloading services provided hereunder during the previous month.  Payment shall be due within ten (15) days of the invoice date.  In the event actual measurements of

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quantities of Shipper’s Crude Oil are unavailable in any month of service, Gatherer may invoice Shipper based on estimated quantities, which shall be corrected to actual quantities once such actual quantities are available.

9.2Late Payments.  Late payments shall accrue interest at the rate of 1.5% per month, or if such interest rate exceeds the maximum rate allowed by law, then the maximum rate allowed by law will be used.  In the event a payment is late by more than sixty (60) days, Gatherer may withhold from delivery Crude Oil volumes of equal value (in US Dollars) to the Dollar amount of the late payment (plus accrued interest) until payment of the late Fees has been made.  Payments received by Gatherer from Shipper shall be attributed to the earliest unpaid invoice issued to Shipper; provided, however, that such payments shall not be attributed to any amounts disputed subject to Section 9.3.

9.3Dispute.  If Shipper, in good faith, disputes the amount of any such invoice or any part thereof, Shipper will pay such amount as it concedes to be correct.  If Shipper disputes the amount due, it must provide supporting documentation acceptable in industry practice to support the amount disputed within 10 Days of the date of such invoice.  If the Parties are unable to resolve such dispute, either Party may pursue any remedy available at law or in equity to enforce its rights under this Agreement.

9.4Audit.  A Party shall have the right, at its own expense, upon reasonable Notice and at reasonable times, to examine and audit and to obtain copies of the relevant portion of the books, records, and telephone recordings of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge, payment, or computation made under this Agreement.  This right to examine, audit, and to obtain copies shall not be available with respect to proprietary information not directly relevant to transactions under this Agreement.  All invoices and billings shall be conclusively presumed final and accurate and all associated claims for underpayments or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and documentation, within the 24 month period following the month of Crude Oil delivery at the Delivery Point(s).  All retroactive adjustments shall be paid in full by the Party owing payment within 30 Days of Notice substantiating such inaccuracy.

9.5Adequate Assurance.  If at any time Shipper assigns the Agreement in connection with the sale of all or substantially all of its assets, or in connection with a merger, consolidation, or other reorganization, at the time of and following such assignment, by Notice to Shipper, Gatherer may require any of the following (individually and collectively, “Adequate Assurance”) prior to Gatherer’s obligation to continue to provide services hereunder:  (1) prepayment of estimated Fees to be held by Gatherer without interest accruing thereon in advance of a delivery month; (2) a cash deposit in an amount satisfactory to Gatherer; (3) a letter of credit at Shipper’s expense in an amount and from a financial institution satisfactory to Gatherer; or (4) a guaranty in an amount and from a third party acceptable to Gatherer.  Shipper shall provide such Adequate Assurance within two (2) Business Days of demand therefore.

9.6Events of Default.  A Party becomes a “Defaulting Party” and the following actions shall constitute “Default” if the Defaulting Party shall (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it; (iii) otherwise become bankrupt

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or insolvent (howsoever evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee or other similar official appointed with respect to it or substantially all of its assets; or (vi) consolidate or amalgamate with, or merge with or into, or transfer all or substantially all of its assets to another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all of the obligations of the Defaulting Party under this Agreement by operation of law or pursuant to an agreement reasonably satisfactory to the other Party (“Non-Defaulting Party”), then the Non-Defaulting Party, in addition to any and all other remedies available hereunder or pursuant to law, shall have at its sole election and upon Notice thereof to the Defaulting Party, the right to immediately withhold, refuse or suspend performance hereunder and the right to terminate this Agreement by designating in any such Notice the effective date of termination (which effective date of termination shall not be earlier than the Day such Notice is given and not later than 20 Days after such Notice is given).

ARTICLE X
TAXES, LIABILITY AND WARRANTIES

10.1Taxes.  Shipper shall pay or cause to be paid, and agrees to indemnify and hold harmless Gatherer from and against the payment of, all excise, gross production, severance, sales, occupation, and all other taxes, charges, or impositions of every kind and character required by statute or by any Governmental Authority with respect to Shipper’s Crude Oil (other than margin or franchise taxes or taxes imposed upon income, profits or gains of Gatherer) and the handling thereof prior to receipt thereof by Gatherer at the CRPs.  Gatherer shall pay or cause to be paid all taxes and assessments, if any, imposed upon Gatherer for the activity of gathering of Shipper’s Crude Oil after receipt and prior to redelivery thereof by Gatherer at the Delivery Point(s).  Neither Party shall be responsible or liable for any taxes or other statutory charges levied or assessed against the facilities of the other Party used for the purpose of carrying out the provisions of this Agreement.  Shipper shall account for and remit all royalties, overrides, and other sums due by Shipper to the owners of the minerals, royalties and other interests in the Crude Oil.  Shipper shall indemnify and save Gatherer harmless from and against all loss, cost, damage, and expense of every character and in kind resulting from any adverse Third Party or Shipper Affiliate claims in respect of royalties, taxes, payments or other charges due on Shipper’s Crude Oil, and Gatherer has the right to suspend its receipt of any of Shipper’s Crude Oil subject to such claims until such claims are resolved to Gatherer’s satisfaction.

10.2Title.  Shipper warrants that it controls or has the right to market the interest in Shipper’s Crude Oil and has the right to ship and/or market Shipper’s Crude Oil free from all liens and adverse claims of title.  Gatherer has the right to suspend its receipt of any of Shipper’s Crude Oil subject to any title claims until they are resolved to Gatherer’s satisfaction

10.3Control and Possession.  As between the Parties, Shipper shall be deemed to be in exclusive control and possession of Shipper’s Crude Oil and responsible for any damage or injury caused thereby prior to the time Shipper’s Crude Oil shall have been delivered to Gatherer at the CRPs, and after the time Shipper’s Crude Oil is redelivered to Shipper at the Delivery Point(s).  After delivery of Shipper’s Crude Oil to Gatherer at the CRPs, Gatherer shall be deemed to be in exclusive control and possession thereof and responsible for any injury or damage caused thereby until the Crude Oil is redelivered to Shipper at the Delivery Point(s).

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10.4Indemnity.  Shipper agrees to indemnify, defend, and hold harmless Gatherer from any and all Losses arising from or out of personal injury or property damage attributable to Shipper’s Crude Oil when Shipper shall be deemed to be in control and possession of Shipper’s Crude Oil as provided in Section 10.3.  Gatherer agrees to indemnify, defend, and hold harmless Shipper from all Losses arising from or out of personal injury or property damage attributable to Shipper’s Crude Oil when Gatherer shall be deemed to be in control and possession of Shipper’s Crude Oil as provided in Section 10.3.  THE INDEMNITIES SET FORTH IN THIS SECTION 10.4 ARE TO BE CONSTRUED WITHOUT REGARD TO THE CAUSES THEREOF, INCLUDING THE NEGLIGENCE OF ANY INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE, OR THE STRICT LIABILITY OF ANY INDEMNIFIED PARTY OR OTHER PERSON.  Each Party agrees that its voluntary and mutual indemnity agreement will be supported by insurance and that such insurance shall not be deemed to be a cap on liability.

10.5Disclaimer of Damages.  A PARTY’S LIABILITY HEREUNDER SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY.  SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED.  NEITHER PARTY SHALL BE LIABLE HEREUNDER TO THE OTHER PARTY OR ITS AFFILIATES FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS (OTHER THAN DIRECT, ACTUAL LOST PROFITS), OR OTHER BUSINESS INTERRUPTION OR SIMILAR DAMAGES, BY STATUTE, IN TORT, OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE.  IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE STRICT LIABILITY OR NEGLIGENCE OF ANY PARTY, WHETHER SUCH STRICT LIABILITY OR NEGLIGENCE BE SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE.

ARTICLE XI
FORCE MAJEURE

11.1Force Majeure.  The term “Force Majeure” shall mean any cause or event not reasonably within the control of the Party whose performance is sought to be excused thereby, including (1) acts of God, strikes, lockouts, or other industrial disputes or disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, tornadoes, hurricanes, storms, severe winter weather, and warnings for any of the foregoing which may necessitate the precautionary shut-down of wells, plants, pipelines, the Facilities, truck unloading facilities; (2) failure of any parties downstream of the Delivery Point(s) (except for downstream parties that are Affiliates of Gatherer) to timely install or provide interconnection or receipt facilities, or other related facilities; (3) floods, washouts, arrests and restraints of governments and people, civil disturbances, explosions, sabotage, breakage or accidents to equipment, machinery, plants, truck unloading facilities, other related facilities, or lines of pipe; (4) the making of repairs or alterations to lines of pipe, the Gathering System, truck unloading facilities, plants or equipment; (5) freezing of wells or lines of pipe; (6) electric power shortages; (7) necessity for compliance with any court order, or any law, statute, ordinance, regulation or order promulgated by a Governmental Authority having or asserting jurisdiction, unless such necessity arises as a result of Gatherer’s or its Affiliates’ failure to comply with any Applicable Law (provided that

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Gatherer shall be permitted to resist in good faith the application to it of any such law by all reasonable legal means); (8) inability to obtain necessary permits, rights of way or materials for construction, maintenance or operations provided same were timely and diligently pursued; (9) inclement weather that necessitates extraordinary measures and expense to construct facilities or maintain operations; and (10) any other causes, whether of the kind enumerated herein or otherwise, not reasonably within the control of the Party claiming suspension, including any such cause or event occurring with respect to the facilities, services, equipment, goods, supplies or other items necessary to the performance of such Party’s obligations hereunder.  “Force Majeure” also includes any event of Force Majeure occurring with respect to the facilities or services of either Party’s Affiliates or service providers providing a service or providing any equipment, goods, supplies or other items necessary to the performance of such Party’s obligations hereunder.

11.2Notice of Force Majeure.  If a Party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this Agreement (other than the obligation to make payments of monies due hereunder), then Party shall give prompt written Notice of the Force Majeure stating facts supporting such claim of inability to perform.  Thereupon, Party’s obligation to perform shall be suspended during the period it is unable to perform because of the Force Majeure, but for no longer period, and this Agreement shall otherwise remain unaffected.  Party shall use due diligence to remove the cause of Force Majeure, where commercially practicable, with all reasonable dispatch; provided, however, that this provision shall not require the settlement of strikes, lockouts, or other labor difficulty, when such course is determined inadvisable by Party.

11.3Release During Force Majeure.  During any event(s) of Force Majeure affecting Gatherer’s ability to transport Shipper’s Crude Oil subject to Dedication, Shipper shall be released from its obligation hereunder to deliver the Crude Oil to Gatherer at the Receipt Point(s) pursuant to Article III.

ARTICLE XII
LAWS AND REGULATIONS

12.1Laws and Regulation.  The Parties acknowledge that all or part of the Facilities may be subject to regulation by the RRC, or other federal or state agencies with jurisdiction of the Facilities and transaction contemplated by this Agreement, or any of their successors.  The Parties agree to comply with all such Applicable Laws, rules and regulations.

12.2Gathering System Rules and Regulations.  The Parties acknowledge that Gatherer is a common carrier for hire, and this Agreement and all gathering services performed by it on the Gathering System for Shipper pursuant to this Agreement, shall be subject to the rules and regulations in Gatherer’s applicable tariffs in effect from time to time (as amended from time to time, the “Rules and Regulations”), including, without limitation, laws and regulations that prevent discrimination in favor of any given shipper or the provision of service for consideration other than the rate set forth in a published tariff; provided, as between Gatherer and Shipper as an Anchor Shipper, if there is a conflict between the terms and conditions of this Agreement and the terms and conditions of the Rules and Regulations, the terms and conditions of this Agreement will govern and control.  A copy of Gatherer’s Rules and Regulations that will be filed with the RRC will be attached as Exhibit E, once it has been filed with the RRC.  Gatherer shall be responsible for filing with the RRC all necessary tariffs and/or amendments to the Rules and Regulations in order to provide to Shipper the transportation services contemplated by this

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Agreement.  For purposes of the Rules and Regulations, this Agreement shall be deemed:  (i) a term Firm Crude Oil Gathering and Transportation Agreement (“TA”) with Gatherer whereby Shipper has agreed upon a Dedication of acreage within an Area of Dedication, (ii) a TA associated with the initial construction of a pipeline and appurtenant facilities of Gatherer or (iii) any agreement of a similar nature referred to in the Rules and Regulations, and shall enjoy all of the rights and benefits provided to such agreements in the Rules and Regulations.

ARTICLE XIII
NOTICES

13.1Notices.  Except for nominations for Crude Oil delivery by Shipper required hereunder, all notices and other communications required or permitted under this Agreement (each, a “Notice”) shall be in writing and addressed as set forth herein.  Any Notice shall be deemed to have been duly made and the receiving Party charged with receipt of such Notice (i) if personally delivered, when received, (ii) if sent by electronic mail, telecopy or facsimile transmission, on the business day on or which such facsimile is successfully transmitted and received, or if such telecopy or facsimile transmission was successfully transmitted and received after 5:00 pm local time of the receiving party, then the next Business Day, (iii) if mailed by certified mail, return receipt requested, the 5th Business Day after mailing, or (iv) if sent by overnight courier, on the day such Notice is successfully delivered to the receiving party.  All Notices shall be addressed as follows.

Gatherer:	Shipper:
Monarch Oil Pipeline, LLC	Jones Energy, LLC
Attn: Chief Financial Officer Attn: Judson Williams	Attn: Senior Marketing Representative Attn: Denise Herbert(1)
5613 DTC Parkway, Suite 310	807 Las Cimas Parkway, Suite 350
Englewood, Colorado 80111	Austin, Texas 78746
Facsimile: (720) 235-0228 Jwilliams@mngllc.com	Facsimile: (512) 328-5394 dherbert@jonesenergy.com

Any Party may, by written Notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made.

ARTICLE XIV
MISCELLANEOUS

14.1Confidentiality.  Each Party (“Information Receiving Party”) shall maintain, for the benefit of the other Party (“Disclosing Party”), in the strictest confidence all information pertaining to the financial terms of or payments under this Agreement, the Disclosing Party’s methods of operation, methods of the Facility, and the like, whether disclosed by the Disclosing Party or discovered by the Information Receiving Party, unless such information either (i)  is in the public domain through no act or omission of the Information Receiving Party or its employees or agents, (ii) was already known to the Information Receiving Party at the time of disclosure and which the Information Receiving Party is free

(1)  [NTD:  Please confirm that this is the correct notice information.]

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to use or disclose without breach of any obligation to any person or entity, (iii) is required to be disclosed by Applicable Law, or (iv) is disclosed to regulators in furtherance of obtaining regulatory approval, provided that such disclosure is provided under seal.  Neither Party shall use such information for its own benefit, publish or otherwise disclose it to others, or permit its use by others for their benefit or to the detriment of the other Party.  Notwithstanding the foregoing, the Information Receiving Party may disclose such information to any auditor or to the Information Receiving Party’s lenders, attorneys, accountants and other personal advisors; any prospective purchaser of the Facility; or pursuant to lawful process, subpoena or court order; provided the Information Receiving Party, in making such disclosure, advises the party receiving the information of the confidentiality of the information and obtains the agreement of said party not to disclose the information.

14.2Assignment.

14.2.1Except as otherwise provided in this Section 14.2, neither Party may assign all or a portion of its rights and obligations under this Agreement without the prior written consent of the non-assigning Party, provided that such consent shall not be unreasonably withheld or delayed.

14.2.2Notwithstanding Section 14.2.1, either Party shall have the right without the prior consent of the other Party to: (i) assign its rights and obligations under this Agreement (in whole or in part) to an Affiliate; (ii) mortgage, pledge, encumber, or otherwise impress a lien, create a security interest or otherwise assign as collateral its rights and interests in and to the Agreement to any lender; (iii) make a transfer pursuant to any security interest arrangement described in (ii) above, including any judicial or non-judicial foreclosure and any assignment from the holder of such security interest to another Person; or (iv) assign the Agreement in connection with the sale of all or substantially all of its assets, or in connection with a merger, consolidation, or other reorganization.  If a Party assigns its rights and obligations under this Agreement (in whole or in part) pursuant to clauses (i) or (iv) above, such Party shall require the assignee to assume such Party’s obligations hereunder and become a signatory to this Agreement, and such assignee shall be bound by the terms herein.

14.2.3If Gatherer desires to sell the Facilities to an unaffiliated third party prior to its completion, including through a change of control (excepting a public offering of equity or other ownership by Gatherer), Gatherer will require the buyer of the Facilities to assume Gatherer’s obligations under this Agreement, along with any future modification to the Facilities contemplated in this Agreement.

14.3Shipper’s Duty to Support.

14.3.1Shipper’s Duty to Support Prior to Commencement Date.  To the extent not inconsistent with Applicable Law, Shipper hereby agrees prior to the Commencement Date: (a) to reasonably support and cooperate — and not to oppose, obstruct or otherwise interfere in any manner, direct or indirect — with the efforts of Gatherer to obtain all governmental, regulatory and other authorizations and approvals necessary for the construction and operation of the Facilities in the form and manner proposed by Gatherer; and (b) to not take, directly or indirectly, any action that (i) is designed to delay review or approval of any petitions or applications to any

27

Governmental Authorities related to the Facilities, or (ii) would materially and adversely affect the Facilities or this Agreement.  Notwithstanding the foregoing, nothing herein shall prevent Shipper from (i) protesting any regulatory or other filings that are in conflict with the terms of this Agreement, and (ii) proceeding in any manner consistent with Applicable Law if this Agreement is terminated or if the Facilities has been abandoned by Gatherer.

14.3.2Shipper’s Duty to Support Rules and Regulations and Tariff Filings.  To the extent consistent with Applicable Law, Shipper hereby agrees during the Term of this Agreement not to protest, complain, or take any action, nor recommend or cause any affiliated entity or other entity to protest, complain, or take any action, that is designed to or may delay review or approval of the filing of the Rules and Regulations and tariffs, including the fees, with the RRC or any other governing body, unless such tariff filings are in conflict with the terms of this Agreement.

14.4Memorandum of Agreement.  The Parties agree to promptly execute and record a Memorandum of Crude Oil Gathering Agreement substantially in the form of Exhibit D following the execution of this Agreement.

14.5Governing Law: Venue and Jurisdiction.  This Agreement shall be construed, enforced, and interpreted according to the laws of the State of Texas, without regard to the conflicts of law rules thereof.  Any action brought in respect of this Agreement must be brought in the state or federal courts sitting in Harris County, Texas

14.6Waiver.  No waiver of any breach of this Agreement by a Party shall be held to be a waiver of any other or subsequent breach.

14.7Amendments.  This Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the Party claiming the benefit of such amendment or waiver.

14.8Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute but one and the same instrument.  Facsimile signatures shall be considered binding.

14.9Entire Agreement.  This Agreement constitutes the entire understanding among the Parties with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements and understandings relating to such subject matter.

14.10Binding Effect.  This Agreement shall be binding upon, and shall inure to the benefit of the Parties hereto and their respective permitted successors and assigns.

14.11Severability.  If any part of this Agreement is held to be void or unenforceable by any court or under any law, that part shall be deemed stricken and all remaining provisions shall continue to be valid and binding upon the Parties.

14.12No Third-Party Beneficiaries.  This Agreement is intended to benefit only the Parties hereto and their respective permitted successors and assigns.

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14.13Contract Revision.  Notwithstanding anything in this Agreement to the contrary, whether express or implied, the Parties do not intend for this Agreement or any provision of this Agreement to be subject to revision by any Governmental Authority, including the RRC.

14.14Future Expansions of the Facilities.  Subject to Gatherer’s rights and obligations under the Rules and Regulations and other Applicable Law, Gatherer shall have the right, at its sole discretion, to expand the capacity of all or parts of the Facilities at any time or from time to time; provided, that no such expansion shall degrade the services provided hereunder.  Gatherer reserves the right to enter into transportation services agreements for the capacity added during any expansion at terms to be determined by Gatherer.  Any such expansion shall not affect the obligations established in this Agreement.

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IN WITNESS WHEREOF, the Parties have executed this Agreement as of the Effective Date.

GATHERER		SHIPPER
MONARCH OIL PIPELINE, LLC		JONES ENERGY, LLC
By:	/s/ Terry Klare	By:	/s/ Jonny Jones
Name:	Terry Klare	Name:	Jonny Jones
Title:	President and COO	Title:	Chief Executive Officer

[SIGNATURE PAGE TO AMENDED AND RESTATED FIRM CRUDE OIL GATHERING AND TRANSPORTATION AGREEMENT]

EXHIBIT A

Dedicated Leasehold (by Section)

“South Lipscomb”, Lipscomb County, Texas

Block 43, H&TC: Sections 61, 64, 65, 67, 68, partial 71, 72, 73, 74, 75, 76, 97, 101, 102, 103, 104, 105, 106, 107, 108, 109, 110, 112, 115, 151, 153, 154, 155, 156, 157, 159, 160, 161, 162, 163, 164, partial 165, 189, 190, 193, 194, partial 196, 198, 200, 204, partial 236, partial 237, 238, 241, 242, partial 244, 248, 252, 255, 259, 271, 272, 282, 285, 286, 287, 288, 289, 324, 328, 329, 331, partial 365, 415, 417, 422, 502

“South Lipscomb”, Hemphill County, Texas

Block 42, H&TC: Sections 61, partial 64, 69, 70, 71, 84, 86, 87, 88, 101 , 104

Block 43, H&TC: Sections 15, 16, partial 17, 25, 26, 27

BS&F Survey: partial in Section 1 and Section 2

Block 1, G&M Survey: Sections 54, 55, 63, 66, 72, 73, n, 78

JF Johnson Survey: Section 1

WO Fisher Survey: Section partial 1

RM Moody Survey: Section 1

JW: Section 2

“Hemphill”, Hemphill County, Texas

Block 41, H&TC: Sections 53, 84, 85, 87, 88, 116, 117, 118, 119, partial 131, 132, 139, 140, 141, partial 142, 163

Block 42, H&TC: Sections 76, 80, 81

Block 1, G&M Survey: Sections 1, 3, 4, 5, 9, 80, 81

Francis, S Survey A-38

James F Survey A-36

Schmidt, H. Survey A-414

EXHIBIT B

Area of Dedication and Area of Mutual Interest

EXHIBIT C-1-A

INITIAL CRPS (BY LOCATION)

BY NOVEMBER 1, 2015

Bailey 271-2H	Waters Ranch 287-2H
Cameron 162-1H	Waters Ranch 287-3H
Cleveland 103-1H	Waters Ranch 287-4H
Cleveland 106-1H	Waters Ranch 287-5H
Cleveland 159-3H	Waters Ranch 289-5H
Garlon Rogers 244-1H	Whitfield Unit 157-3H
Houser 200-1H	Wolfcreek 161-1H
Houser 241-2H	Wolfcreek 161-2H
Houser 241-4H	Wolfcreek 161 3H
Houser 241-5H
Houser 242-3H
Houser 242-4H
Houser 242-5H
Houser 288-2H
Houser 288-3H
Houser 288-4H
Houser 288-5H
LCU 155-1H
LCU 155-3H
Lubbock 155-4H
Lubbock Unit 156-1H
Lubbock Unit 156-2H
Mary Snyder 157-1H
Mary Snyder 157-2H
May 163-1H
Parnell Ranch 165-2H
Parnell Ranch 165-3H
Peery 200-2H
Peery 331 1H
Peery 331 2H
Peery 331-4H
Peery 331-5H
RP Bussard 106-1H
RP Rader 190-4H
RP Rader 190-5H

1

INITIAL CRPs (BY LOCATION)

BY MARCH 31, 2016

Abraham 196-2H (PUD)	Houser 242-4H	Rader Cleveland (SA) 160-1H
Benjamin 112 1H	Houser 242-5H	Rader Cleveland (SA) 160-3H
Bailey 271-2H	Houser 288-2H	Rader Cleveland (SA) 160-4H
Brainard 25-1H	Houser 288-3H	Rader Cleveland (SA) 160-5H
Brainard 25-2H	Houser 288-4H	Rader Cleveland 160-2H
Brainard 25-3H	Houser 288-5H	RP Bussard 106-1H
Brainard 25-4H	Imboden 73-2H	RP Jones Trust 189-1H
Brainard 25-5H	Imboden 73-3H	RP Jones Trust 189-2H
Brainard 26-1H(PUD)	Imboden 73-4H	RP Jones Trust 189-3H
Brainard 26-2H	Imboden 73-5H	RP Jones Trust 189-4H
Brainard 26-3H	Jones Trust 272-3H	RP Rader 190-4H
Brainard 26-4H	Jones Trust 272-4H	RP Rader 190-5H
Brainard 27-2H	Kellin 65-1H	RP Tubb 194-1H
Brainard 27-3H	Kelln 65-2H	RP Tubb 194-4H
Cameron 162-1H	Kelln 65-3H	RP Tubb 194-5H
Cleveland 103-1H	Kelln 65-4H	Snyder 15 2H
Cleveland 103-2H	LCU 155-1H	Snyder 15-4H
Cleveland 103-4H	LCU 155-3H	Snyder 15-5H
Cleveland 103-5H	Lubbock 155-2H	Stanley 280-1H
Cleveland 103-6H	Lubbock 155-4H	Urschell 72-1H
Cleveland 106-1H	Lubbock Unit 156-1H	Urschell 72-5H
Cleveland 108 1H	Lubbock Unit 156-2H	Waters Ranch 287-2H
Cleveland 108 2H	Margie 153-1H	Waters Ranch 287-3H
Cleveland 108 3H(PUD)	Marshall Winston 54-2H	Waters Ranch 287-4H
Cleveland 108 5H(PUD)	Mary Snyder 157-1H	Waters Ranch 287-5H
Cleveland 110 1H	Mary Snyder 157-2H	Waters Ranch 289-5H
Cleveland 159-3H	May 163-1H	Wheat 252-5H
Foster 248-3H	McQuiddy 17-4H	Wheat 255-2H
Foster Unit 248-4H	McQuiddy 64-1H	Whitfield Unit 157-3H
Frances 72 1H	Parnell Ranch 165-2H	Wolfcreek 161-1H
Frances 72-2H	Parnell Ranch 165-3H	Wolfcreek 161-2H
Garlon Rogers 244-1H	Peery 200-2H	Wolfcreek 161 3H
Haugen 72-1H	Peery 331 1H	Wright 75-1H
Haugen 72-2H	Peery 331 2H	Wright 75-2H
Houser 200-1H	Peery 331-4H	Wright 75-3H
Houser 241-1H	Peery 331-5H	Wright 75-4H
Houser 241-2H	Popham 193-1H	Wright 75-5H
Houser 241-4H	Popham 193-4H
Houser 241-5H	Popham Unit 193-2H
Houser 242-1H	Popham Unit 193-3H
Houser 242-2H	Pundt 244-1H
Houser 242-3H

2

EXHIBIT C-1-B

JONES TRUCKED WELLS

Bailey 271-1H

Cleveland 159-1H

Cleveland 159-2H

Foster 248 1H

Houser 288-1H

Lockhart a 36 8HR

Murl Kenyon A 35-3H

Peery 200 1H

Roxie 282-3H

Roxie 282-5H

Roxie 282-6H

RP Rader 190 1H

Sallie Lee 151-1H

Snyder 15-3H

Wheat 252-1H

Wheat 252-2H

Wheat 252-3H

Wheat 252-4H

Wheat 255-1H

Wheat 255-3H

EXHIBIT C-1-C

MONARCH TRUCKED WELLS

Brainard 27-1H	Porter 324 1H
Cleveland 103-3H	Porter 324 2H
Cleveland 107-1H	Porter 324 3H
Cleveland 159-5H	Porter 324 4H
Cleveland 67-1H	Porter 324 5H
Cleveland 68-1H	Rogers Unit 237 1H
Elise 286-3H	Roxie 282-2H
Elise 286-4H	Roxie 282 4H
Elise 286-5H	RP Rader 190-3H
Foster Unit 248-2H	RP Tubb 194-2H
Foster-Foster Unit (SA) 248-1H	Snyder 15-6HT
Hand 16-1H	Waters Ranch 287-1H
Hand 16-2H
Hand 16-3H
Hand 16-4H
Hand 16-5H
Imboden 73-1H
Jones Trust 189-1H
Jones Trust 272-2H
Katy 285-2H
Katy 285-3H
Katy 285-4H
Kelln 365-1H
McQuiddy 17-1H
McQuiddy 17-2H
McQuiddy 17-3H
McQuiddy 17-5HT
Nix 70-1H
Parnell Ranch 165-1H
Peyton Ranch 417-1H
Peyton Ranch 417-2H
Peyton Ranch 417-3H
Peyton Ranch 417-4H
Peyton Ranch 417-5H

Hand 16-1H

EXHIBIT C-1-D

JONES TRUCKED WELLS THAT MAY BE CONNECTED TO THE SYSTEM
	Marshall Winston 77-1H
	Marshall Winston 78-1H
	Nix 71-1H(PUD)
	Nix 84-1H
	Nix 84-2H
	Nix 84-3H
	Nix 84-4H
	Nix 84-5H
	Nix 86-1H
	Nix 87-1H
	Nix 88-1H

EXHIBIT C-2

Flow Diagram of a Typical CRP Installation

EXHIBIT C-3

Casey Station Flow Diagram

EXHIBIT C-4

Osborn Station Flow Diagram

EXHIBIT D

Form of Memorandum of Agreement

MEMORANDUM OF CRUDE OIL GATHERING AGREEMENT

THIS MEMORANDUM OF CRUDE OIL GATHERING AGREEMENT (this “Memorandum”) is entered into as of the       day of                , 2015 by and between MONARCH OIL PIPELINE, LLC, a Delaware limited liability company (“Monarch”), with a mailing address of 5613 DTC Parkway, Suite 310, Englewood, Colorado 80111, and JONES ENERGY, LLC, a Texas limited liability company (“Jones” or “Shipper”), with a mailing address of 807 Las Cimas Parkway, Suite 350 Austin, TX 78746.  Monarch and Jones are referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Monarch and Jones have entered into a Firm Crude Oil Gathering And Transportation Agreement, dated September 26, 2014 (the “Agreement”), pursuant to which Monarch intends to construct (1) a crude oil gathering system, (2) a storage tanking facility and related equipment, and (3) a crude oil transportation system to Plains Pipeline, LP’s Reydon Station located in Roger Mills County, Oklahoma, and the Osborn Station and interconnect with the Valero Piper Station located in Lipscomb County, Texas, which facilities collectively are referred to as the “Pipeline”.

WHEREAS, Shipper holds certain oil and gas leases located in Lipscomb and Hemphill Counties, Texas, that is referred to in the Agreement as an “Area of Dedication” and is further described in Exhibit B to the Agreement as (i) “South Lipscomb” and located in Lipscomb and Hemphill Counties, Texas and a two (2) mile radius surrounding the South Lipscomb Area, and (ii) “Hemphill” and located in Hemphill County, Texas, and a two (2) mile radius surrounding the Hemphill Area, and from which Shipper’s Crude Oil is dedicated to the Agreement.

WHEREAS, Shipper has Crude Oil production from the Area of Dedication that it desires to have gathered and transported by Monarch on and through the Pipeline;

WHEREAS, in exchange for Shipper’s commitment to ship Crude Oil produced from its oil and gas leases in the Area of Dedication for a specified term, Monarch is willing to gather and transport a specified volume of Crude Oil for Shipper for a specified term and at a committed transportation fee on the Pipeline, subject to and upon the terms and conditions of the Agreement.

WHEREAS the Primary Term of the Agreement is ten (10) years from the Commencement Date, with an automatic renewal provision for additional one (1) year Secondary Terms.  Either Party may terminate the Agreement by written Notice to the other Party not less than one (1) year prior to the Primary Term or any renewed, Secondary Term.

WHEREAS, Monarch and the Shipper desire to provide notice of the Agreement.

NOW, THEREFORE, in consideration of the foregoing and the mutual promises and covenants set forth in the Agreement, Monarch and Jones agree and provide notice as follows:

1.Recitals; Capitalized Terms.  The foregoing recitals are true and accurate and are incorporated herein by reference to such recitals.  Capitalized terms not defined in this Memorandum have the meaning ascribed to them in the Agreement.

2.Dedicated Acreage.  To the extent Shipper commits to ship Crude Oil produced from its oil and gas leases for a specified term, such dedication shall mean all of Shipper’s recoverable Crude Oil or Shipper’s Affiliate’s recoverable Crude Oil produced from oil and gas wells located within the Area of Dedication, as set forth in Exhibit B to the Agreement and Attachment A attached hereto, in which Shipper or its Affiliates now or hereafter owns, controls, acquires, and has the right to sell, market (as such marketing rights may change from time to time), or otherwise dispose of and that is not subject to a Prior Dedication as of the Effective Date of the Agreement (or, for subsequently acquired interests within the Area of Dedication, that is not subject to a Prior Dedication as of the date of acquisition), and that is not otherwise released pursuant to the Agreement.

3.Conflict.  In the event of any conflict between the terms of this Memorandum and the terms of the Agreement, the terms of the Agreement will govern and control.

[The remainder of this page is intentionally blank—signature pages follow.]

Texas RRC No.          

EXHIBIT E

Tariff No.     Filed at the RRC

MONARCH OIL PIPELINE, LLC

TEXAS RAILROAD COMMISSION TARIFF

CONTAINING RATES, RULES, AND REGULATIONS

FOR

INTRASTATE GATHERING AND TRANSPORTATION SERVICE

BETWEEN POINTS WITHIN THE STATE OF TEXAS

ON

GATHERING SYSTEM/PIPELINE

EFFECTIVE:                  ,            

FILED WITH THE COMMISSION ON:                 ,            

Issued by:	Compiled by:
Name:	Name:
Title:	Title:
Entity:	Entity:
Address:	Address:
City, State:	City, State:
[Other Contact info]	[Other Contact info]

Monarch Texas RRC No.          

GATHERING AND TRANSPORTATION TARIFF

TABLE OF CONTENTS

1.	DEFINITIONS; RULES OF CONSTRUCTION		1
	1.1.	DEFINITIONS	1
	1.2.	RULES OF CONSTRUCTION	1
2.	GATHERING AND TRANSPORTATION SERVICES		1
	2.1.	DEDICATED FIRM SHIPPER	1
	2.2.	NON-DEDICATED SHIPPER	2
	2.3.	ANNUAL FEE ADJUSTMENTS	3
	2.4.	CRPS AND DELIVERY POINTS	3
	2.5.	VOLUMES	3
	2.6.	SUMMARY TABLE	3
3.	RULES AND REGULATIONS		4
	3.1.	QUALITY SPECIFICATIONS	4
	3.2.	NOMINATIONS	5
	3.3.	INTERRUPTION AND CURTAILMENT	5
	3.4.	PRORATION POLICY	6
	3.5.	PRIORITY CAPACITY	6
	3.6.	IDENTITY OF CRUDE OIL	6
	3.7.	BILLING AND PAYMENT	7
	3.8.	INDEMNITY	7
	3.9.	DISCLAIMER OF DAMAGES	7
	3.10.	FORCE MAJEURE	8
	3.11.	FACILITIES LOSS ALLOWANCE	8
	3.12.	LINE FILL AND TANK FILL	8

Attachment 1.1 (Definitions)

Attachment 2.4 (CRPS and Delivery Points)

i

GATHERING AND TRANSPORTATION TARIFF

The rates published in this tariff (“Tariff”) are for the gathering and transportation of Crude Oil by Monarch Oil Pipeline, LLC (“Carrier”) on the Facilities, subject to the terms, conditions, rules and regulations (“Rules and Regulations”) set forth below to be effective as of             ,     (“Effective Date”).

1.DEFINITIONS; RULES OF CONSTRUCTION

1.1.Definitions.

As used in this Tariff, terms defined in Attachment 1.1 have the meanings set forth therein.

1.2.Rules of Construction.

Unless the context of this Tariff requires otherwise, the plural includes the singular, the singular includes the plural, and “including” has the inclusive meaning of “including without limitation.”  The words “hereof”, “herein”, “hereby”, “hereunder”, and other similar terms of this Tariff refer to this Tariff as a whole and not exclusively to any particular provision of this Tariff.  All pronouns and any variations thereof will be deemed to refer to masculine, feminine, or neuter, singular, or plural, as the identity of the Person or Persons may require.  Unless otherwise expressly provided, any agreement, instrument, or Applicable Law defined or referred to herein means such agreement or instrument or Applicable Law as from time to time amended, modified, or supplemented, including (in the case of agreements or instruments) by waiver or consent and (in the case of Applicable Law) by succession of comparable successor law and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein.

2.GATHERING AND TRANSPORTATION SERVICES

2.1.Dedicated Firm Shipper.

2.1.1.Subject to the other terms and conditions of this Tariff, a Shipper may become a “Dedicated Firm Shipper,” if Shipper enters a Gathering and Transportation Agreement (“Dedicated Firm Shipper Agreement”) with Carrier for a primary term of at least 10 years (“Primary Term”) that obligates Shipper to Dedicate all of Shipper’s Crude Oil (as defined below in Section 2.1.2) to Carrier’s existing or future Central Receipt Points (“CRPs”) (either (i) gathering pipeline connections, or (ii) non-pipeline truck deliveries at Carrier’s loading/unloading facilities at locations specified in the Tariff (“LUFs”)).

2.1.2.In order to become Dedicated Firm Shipper, the Shipper must dedicate to Carrier and/or its Affiliates for the term of the Dedicated Firm Shipper Agreement, all of Shipper’s recoverable Crude Oil, or its Affiliates Recoverable Crude Oil produced from oil and gas wells located within an area of at least 30,000 acres in which Shipper or its Affiliates (as of the effective date of the Dedicated Firm Shipper Agreement) owns, controls, acquires, and has the right to sell, market (as such marketing rights may change from time to time), or otherwise dispose of and that

1

is not subject to a Prior Dedication at that time (or, for subsequently acquired interests within the Area of Dedication, that is not subject to a Prior Dedication as of the date of acquisition) (“Dedication”).  Shipper’s Crude Oil subject to Shipper’s Dedication shall be delivered by Shipper to Carrier and/or its Affiliates either at the CRPs or at the LUFs where Carrier and/or its Affiliates will receive Shipper’s Crude Oil for its transportation in accordance with the Dedicated Firm Shipper Agreement.

2.1.3.Subject to the terms and conditions of this Tariff and the Dedicated Firm Shipper Agreement, a Dedicated Firm Shipper will have “Firm Capacity Rights” during each Month of the Primary Term to ship 5,000 Barrels per Day of Shipper’s Crude Oil to the Valero Piper Station Delivery Point (unless otherwise provided in the Dedicated Firm Shipper Agreement), with the following adjustments:

(a)after the first 5 years of the Primary Term, Carrier will adjust the available capacity annually based on 120% of Dedicated Firm Shipper’s deliveries of Barrels of Crude Oil to the Gathering System averaged for the immediate prior calendar year, and

(b)Carrier will only make an upward adjustment if sufficient firm capacity is available to accommodate such adjustment.

If there is additional available capacity, Dedicated Firm Shipper may also ship nominated excess volumes accepted by Carrier.

2.1.4.For volumes described in Section 2.1.3, Dedicated Firm Shipper will pay Carrier, as applicable:

(a)a “Gathering Fee” of $2.10 per Barrel for any of Shipper’s Crude Oil that is either (1) delivered to Carrier at a CRP for transportation to the Delivery Point(s), (2) loaded and received by Carrier as truck receipts at any of Shipper’s wells and delivered to Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s), or (3) delivered to Carrier at Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, as truck receipts for transportation to the Delivery Point(s)  from any well that Carrier and Shipper have agreed will be subject to the Gathering Fee described in this Section 2.1.4(a); and

(b)an “Unloading and Transportation Fee” of $1.00 per Barrel for all Shipper’s Crude Oil delivered to Carrier at Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s) (other than the wells described in Section 2.1.4(a)(3)).

Except that, if Dedicated Firm Shipper elects to receive Priority Capacity under Section 3.5.2 with respect to proration, Shipper shall pay Carrier, as applicable, a fee of either (individually or together, the “Priority Capacity Rate”) (i) $2.11 per Barrel for any of Shipper’s Crude Oil that is either (a) delivered to Carrier at a CRP for transportation to the Delivery Point(s), (b) loaded and received by Carrier

2

as truck receipts at any of Shipper’s wells and delivered to Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s), or (c) delivered to Carrier at Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, as truck receipts for transportation to the Delivery Point(s) from any well that Carrier and Shipper have agreed will be subject to the Priority Capacity Rate described in this Section 2.1.4(i), or (ii) $1.01 per Barrel for all Shipper’s Crude Oil delivered to Carrier at Carrier’s LUFs at the Casey Station or the Osborn Station, as applicable, for transportation to the Delivery Point(s) (other than the wells described in Section 2.1.4(i)(c)).

2.2.Non-Dedicated Shipper.

A Shipper that is not a Dedicated Firm Shipper is a “Non-Dedicated Shipper,” if that Shipper enters a “Non-Dedicated Shipper Agreement” with Carrier to tender Shipper’s Crude Oil at Carrier’s CRP(s) for transport to the Delivery Point(s), subject to Gathering System availability and compliance with the other terms and conditions of this Tariff.  The applicable “Non-Dedicated Shipper Rate” will be determined if and when a Non-Dedicated Shipper requests service under this Tariff.

2.3.Annual Fee Adjustments.

The fees stated in Section 2.1 (for Dedicated Firm Shippers) and Section 2.2 (for Non-Dedicated Shippers) will be adjusted each July 1 (“Annual Adjustment”) in accordance with FERC indexing methodology as described in 18 C.F.R. § 342.3, subject to the following qualifications.

2.3.1.In a given index year (July 1 through June 30), Carrier’s maximum annual fee adjustment shall be the lesser of (a) the generally applicable index adjustment as published by FERC for that given index year and (b) 3%.

2.3.2.In the event that application of the generally applicable index adjustment as published by FERC for a given index year would result in a rate decrease, Carrier shall not be required to decrease its rates by more than 3%.

2.3.3.Any such rate adjustment shall be prorated for the first index year Carrier is in service, by multiplying (i) the lesser of the index adjustment or 3% by (ii) a fraction, the numerator of which is the number of Days between the commencement date under the applicable Shipper Agreement and June 30 of the index year and the denominator of which is 365.  The Gathering Fee, the Unloading and Transportation Fee, and the Priority Capacity Rate shall never be lower than the rate under this Tariff.

2.4.CRPs and Delivery Points.

The initial CRPs and Delivery Points are identified in Attachment 2.4, as may be updated by from time to time.

2.5.Volumes.

Rates will be charged on all volumes received by Carrier at the CRPs.

3

2.6.Summary Table.

The following table summarizes the rates published in this Tariff for Crude Oil transport as described in Section 2 of this Tariff, subject to the Rules and Regulations set forth in Section 3.

Dedicated Firm Shippers		Rates/Fees (subject to Annual Adjustment under § 2.3)
From any CRP (other than LUFs)	To any applicable Delivery Point	Gathering Fee of $2.10 per Barrel (or $2.11 per Barrel for Priority Capacity Rate)
From any CRP that is an LUF	To applicable Delivery Point	Unloading and Transportation Fee of $1.00 per Barrel (or $1.01 per Barrel for Priority Capacity Rate)

Non-Dedicated Shippers		Rates/Fees (subject to Annual Adjustment under § 2.3)
From any CRP (other than LUFs)	To any applicable Delivery Point	Non-Dedicated Shipper Rate
From any CRP that is an LUF	To applicable Delivery Point	Non-Dedicated Shipper Rate

3.RULES AND REGULATIONS

3.1.Quality Specifications.

3.1.1.Shipper’s Crude Oil must be of a quality acceptable to each of the receiving facilities immediately downstream of the Delivery Point(s) (“Receiving Facilities”), in its natural produced state after normal oilfield lease operations and commercially free of dirt, sediment and chemicals foreign to virgin Crude Oil, including, but not limited to, chlorinated and/or oxygenated hydrocarbons, lead and hazardous or industrial wastes.  Notwithstanding the foregoing, Carrier shall have the right, without prejudice to any other remedy available to Carrier, to reject any Crude Oil that fails to meet the Quality Specifications (“out of spec”), even after delivery to Carrier, and to discontinue accepting Shipper’s Crude Oil for so long as such conditions exist.  Any acceptance by Carrier of out of spec Crude Oil in one instance shall not be deemed as a waiver by Carrier to reject out of spec Crude Oil at a later time.  Shipper shall be liable for and shall indemnify Carrier and hold it harmless against all direct costs and Losses (including loss of revenues) incurred by Carrier for damage to Carrier’s Facilities or Third Party Crude Oil

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caused by Shipper delivering Crude Oil failing to meet the Quality Specifications or for introduction of contaminates into the Gathering System, which may include costs associated with draining the Gathering System facilities, decontaminating the Gathering System facilities, and refilling it with Line Fill and associated loss of revenues.  In addition, Shipper warrants that Shipper’s Crude Oil:

(a)shall contain less than 0.4% sulfur by weight;

(b)shall be of an API Gravity not to exceed 60º when corrected to 60º Fahrenheit; and

(c)shall not contain more than 1% by volume basic sediment and water (“BS&W”) and other impurities, or on an individual basis, water shall not be more than 0.3% by volume and basic sediment shall not be more than 0.7% by volume as determined by the average of the representative samples.  If any of Shipper’s Crude Oil fails to meet the BS&W and Carrier has the facilities to provide treatment service for BS&W, Shipper shall pay Carrier a fee, to be mutually agreed by the parties, and Carrier shall treat Shipper’s Crude Oil to bring it into compliance with the BS&W.

(Collectively, the “Quality Specifications”).

3.1.2.Carrier warrants that the commingled Crude Oil in the Gathering System common stream at the Delivery Point(s) shall not exceed an API Gravity of the lesser of (x) 47.9 or (y) the maximum API gravity requirements of the Receiving Facilities.

3.2.Nominations.

Crude Oil will be transported by Carrier only under a nomination accepted by Carrier.  Any Shipper desiring to nominate Crude Oil for transportation shall make such nomination to Carrier prior to 5 p.m. Central Standard Time/Central Daylight Saving Time, whichever is applicable, on or before the 20th day of the Month preceding the Month during which transportation under the nomination is to begin; except that, if space is available for the current movement, Carrier has the right to accept a nomination of Crude Oil for transportation after the 20th day of the Month preceding the Month during which transportation under the nomination is to begin.  When the 20th day of the Month falls on a weekend or holiday, nominations will be required prior to 5 p.m. Central Standard Time/Central Daylight Saving Time, whichever is applicable, on the immediately preceding workday.  Shippers must submit a separate nomination for each calendar Month.  Each nomination must state the volume of Shipper’s Crude Oil and the Delivery Point(s), and contain other information reasonably required by Carrier.

3.3.Interruption and Curtailment.

3.3.1.Carrier may “Interrupt” or “Curtail”, meaning respectively to stop or reduce transportation service to Shipper and Third Party shippers for such periods of time as it may reasonably require for the purpose of effecting or allowing any repairs, maintenance, replacement, upgrading or other work related to the Facilities, or

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upstream/downstream facilities in circumstances which do not constitute Force Majeure.

(a)A “Curtailment” or “Curtailment event” does not include Shipper’s Default or an inability to receive Crude Oil by any entity not an Affiliate of Carrier downstream of the Delivery Point(s) for any reason.

(b)If such Interruption or Curtailment is due to a planned outage, Carrier shall give Shipper prior notice of such Interruption or Curtailment as soon as reasonably possible.  If such Interruption or Curtailment is unforeseen, Carrier shall give Shipper notice of such Interruption and Curtailment as soon as reasonably possible.  Carrier shall use reasonable commercial efforts to minimize the extent and duration of any Interruption or Curtailment and the impact of such Interruption or Curtailment on the operation of the Facilities.

3.4.Proration Policy.

3.4.1.When Shippers in the aggregate nominate more Crude Oil to Carrier than it can transport, the transportation furnished by Carrier will be prorated among all such Shippers in proportion to the amounts nominated by each, based on the capacity of the Gathering System or any line segment thereof, as applicable (“Proration”).  No nominations will be considered beyond the amount that the Shipper requesting the shipment has readily accessible for shipment.

3.4.2.Notwithstanding the general Proration Policy set forth in Section 3.4.1, in the event of an interruption or curtailment Dedicated Firm Shippers may elect to receive Priority Capacity in accordance with Section 3.5, which will not be subject to the proration methodology set out above.  Such Priority Capacity will not exceed 90% of the available capacity of the pipeline.

3.5.Priority Capacity.

3.5.1.Carrier will follow a Proration policy as set forth in these Rules and Regulations when the amount of Crude Oil nominations properly submitted by all system Shippers exceeds the Gathering System’s capacity for a given Month.  The capacity available for service during the Month of allocation (design capacity less any reduction in capacity because of Interruption and Curtailment or Force Majeure) is the “Prorationed Capacity.”

3.5.2.Carrier will maintain ninety percent (90%) of the Prorationed Capacity for Dedicated Firm Shippers (“Priority Capacity”).  Dedicated Firm Shippers are eligible to make a Priority Capacity election should the Facilities enter into a period of Proration by electing to pay the Priority Capacity Rate set forth in Section 2.6.  In the event that the Prorationed Capacity is less than design capacity (as a result of, for example, Interruption or Curtailment or Force Majeure), the Priority Capacity available for each Dedicated Firm Shipper will be allocated pro rata in accordance with each Dedicated Firm Shipper’s respective committed volume.

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3.6.Identity of Crude Oil.

Crude Oil will be accepted for transportation only on condition that such Crude Oil will be subject to changes in quality and composition while in transit or as may result from unavoidable contamination, and Carrier will not be obligated to make delivery of the identical Crude Oil received for transportation.  Carrier may, therefore, make delivery of Crude Oil out of common stocks of similar Crude Oil on hand at a Delivery Point.

3.7.Billing and Payment.

3.7.1.On or before the 15th Day of the Month, Carrier shall bill Shipper each Month for the Fees for gathering and unloading services provided hereunder during the previous Month.  Payment shall be due within 15 Days of the invoice date.  In the event actual measurements of quantities of Shipper’s Crude Oil are unavailable in any Month of service, Carrier may invoice Shipper based on estimated quantities, which shall be corrected to actual quantities once such actual quantities are available.

3.7.2.Late payments shall accrue interest at the rate of 1.5% per Month, or if such interest rate exceeds the maximum rate allowed by law, then the maximum rate allowed by law will be used.  In the event a payment is late by more than sixty (60) Days, Carrier may withhold from delivery an amount of Crude Oil volumes of equal value (in US Dollars) to the US Dollar amount of the late payment (plus accrued interest) until payment of the late Fees has been made.  Payments received by Carrier from a particular Shipper shall be attributed to the earliest unpaid invoice issued to that Shipper; provided, however, that such payments shall not be attributed to any amounts disputed subject to Section 3.7.3.

3.7.3.If Shipper, in good faith, disputes the amount of any such invoice or any part thereof, Shipper will pay such amount as it concedes to be correct.  If Shipper disputes the amount due, it must provide supporting documentation acceptable in industry practice to support the amount disputed within 10 Days of the date of such invoice.

3.7.4.All invoices and billings shall be conclusively presumed final and accurate and all associated claims for underpayments or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and documentation, within the 24 Month period following the Month of Crude Oil delivery at the Delivery Point(s).  All retroactive adjustments shall be paid in full by the Party owing payment within 30 Days of Notice substantiating such inaccuracy.

3.8.Indemnity.

Carrier’s and Shipper’s indemnity obligations are set forth in the Shipper Agreement; provided that, in any event, to the extent permitted by Applicable Law, Shipper will indemnify, defend, and hold harmless Carrier from any and all Losses arising from or out of personal injury or property damage attributable to Shipper’s Crude Oil when Shipper shall be deemed to be in control and possession of Shipper’s Crude Oil.  Shipper agrees that its

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indemnity obligations will be supported by insurance and that such insurance shall not be deemed to be a cap on Shipper’s liability in respect of such indemnity obligations.

3.9.Disclaimer of Damages.

CARRIER’S AND SHIPPER’S LIABILITY OBLIGATIONS ARE SET FORTH IN THE SHIPPER AGREEMENT; PROVIDED THAT, IN ANY EVENT, CARRIER’S LIABILITY HEREUNDER SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY.  SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED .  CARRIER SHALL NOT BE LIABLE HEREUNDER TO THE OTHER PARTY OR ITS AFFILIATES FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS (OTHER THAN DIRECT, ACTUAL LOST PROFITS), OR OTHER BUSINESS INTERRUPTION OR SIMILAR DAMAGES, BY STATUTE, IN TORT, OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE.

3.10.Force Majeure.

If a party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under the Tariff (other than the obligation to make payments of monies due thereunder), then that party shall give prompt written notice of the Force Majeure stating facts supporting such claim of inability to perform.  Thereupon, that party’s obligation to perform shall be suspended during the period it is unable to perform because of the Force Majeure, but for no longer period, and the Tariff shall otherwise remain unaffected.  The party shall use due diligence to remove the cause of Force Majeure, where commercially practicable, with all reasonable dispatch; provided, however, that this provision shall not require the settlement of strikes, lockouts, or other labor difficulty, when such course is determined inadvisable by the party.

3.11.Facilities Loss Allowance.

Each Shipper shall be allocated the Facilities Loss Allowance on a pro-rata basis to cover all normal course of business losses sustained on the Facilities due to evaporation, measurement, and other losses in transit.

3.12.Line Fill and Tank Fill.

3.12.1.Each Shipper must provide its pro rata share of Barrels of Crude Oil for Line Fill and Tank Fill required for operation of the Gathering System, Casey Station, the Osborn Station interconnect and the Valero Piper Station, as applicable.  Each quarter, Carrier will provide an adjustment for each Shipper’s account to properly proration the quantity of Line Fill and Tank Fill among all Shippers on the Gathering System, Casey Station, and the Osborn Station interconnect, as applicable, and to account for any changes to each Shipper’s pro rata share of Barrels of Crude Oil for Line Fill and Tank Fill required for operation of the Gathering System, Casey Station, and the Osborn Station interconnect, as applicable.

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3.12.2.Crude Oil furnished for Line Fill and Tank Fill by a Shipper may be withdrawn from the Gathering System only after (i) that Shipper’s Dedicated Firm Shipper Agreement or Non-Dedicated Shipper Agreement (as applicable), has expired or terminated, (ii) that Shipper’s inventory balances have been reconciled between Carrier and Shipper, and (iii) all fees due and payable to Carrier by that Shipper have been fully and finally paid.

3.12.3.After satisfaction of the items described in Section 3.12.2, Carrier shall have a reasonable period of time to complete administrative and operational requirements incident to that Shipper’s withdrawal of the Crude Oil.

3.12.4.Any losses to Line Fill and/or Tank Fill due to evaporation, measurement or other losses in transit shall be subject to allocation among all Shippers on a pro rata basis but any individual Shipper’s allocation during a Month shall never exceed 0.2%, of that Shipper’s Line Fill or Tank Fill, as applicable.

[The remainder of this page is intentionally left blank.

The next page of this document is Attachment 1.1]

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Texas RRC No.             

ATTACHMENT 1.1

DEFINITIONS

Terms defined in this Attachment 1.1 will have the meanings set forth in this Attachment.

TERM	DEFINITION
1.Affiliate	Any Person, corporation, partnership, limited partnership, limited liability company, or other legal entity, whether of a similar or dissimilar nature, which (i) controls, either directly or indirectly, a Party, or (ii) is controlled, either directly or indirectly, by such Party, or (iii) is controlled, either directly or indirectly, by a Person or entity which directly or indirectly controls such Party. As used in this definition, “control” means the ownership of (or the right to exercise or direct) 50% or more of the voting rights in the appointment of directors of such entity, or 50% or more of the interests in such entity.
2.Annual Adjustment	As defined in Section 2.3.
3.API	American Petroleum Institute.
4. API Gravity	Gravity determined in accordance with the ASTM International (formerly known as the American Society for Testing and Materials) (“ASTM”) Designation D-287-82 or the latest revision thereof.
5.Applicable Law	With respect to any Person, property or matter, any of the following applicable thereto: any statute, law, regulation, ordinance, rule, judgment, rule of common law, order, decree, governmental approval, concession, grant, franchise, license, agreement, directive, ruling, guideline, policy, requirement or other governmental restriction or any similar form of decision of, or determination by, or any interpretation, construction or administration of any of the foregoing, by any Governmental Authority, in each case as amended.
6.ASME	American Society of Mechanical Engineers.
7.ASTM	ASTM International, formerly known as the American Society for Testing and Materials.

Monarch Texas RRC No.              , Attachment 1.1

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8.Barrel (“bbl”)	42 United States gallons of 231 cubic inches per gallon at a temperature of 60 degrees Fahrenheit.
9.BPD	Barrels per Day.
10.BS&W	Basic sediment, water and other impurities.
11.Business Day	Any Day other than a Saturday, Sunday or other Day on which banks in the State of Texas are permitted or required to close.
12.Carrier	As defined in the first paragraph.
13.Central Receipt Points	The points described in Attachment 2.4.
14.Commission	The Railroad Commission of Texas or any successor agency with jurisdiction.
15.CRPs	As defined in Section 2.1.1.
16.Crude Oil	Naturally occurring, unrefined petroleum product composed of hydrocarbon deposits of varying grades.
17.Curtail	As defined in Section 3.3.1.
18.Curtailment	As defined in Section 3.3.1.
19.Day	A period of 24 consecutive hours commencing at 7:00 A.M. prevailing Central Time.
20.Dedicated Firm Shipper	As defined in Section 2.1.1.
21.Dedicated Firm Shipper Agreement	As defined in Section 2.1.1.
22.Dedication	As defined in Section 2.1.2.

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23.	Delivery Point(s)	The Delivery Points Described in Attachment 2.4.
24.	Effective Date	As defined in the first paragraph.
25.	Facilities	Carrier’s facilities constituting the Gathering System, Casey Station, the Osborn Station, and Carrier’s interconnection facilities with Valero’s facilities at or near the Valero Piper Station in Lipscomb County, Texas.
26.	Facilities Loss Allowance	The Facilities’ actual losses due to evaporation, measurement, or other losses in transit.
27.	Fees	The Gathering Fee, Unloading and Transportation Fee, Priority Capacity Rate, and any other fees described in or authorized by this Tariff.
28.	FERC	Federal Energy Regulatory Commission or its successor agency.
29.	Firm Capacity Rights	As defined in Section 2.1.3.
30.	Force Majeure	Any cause or event not reasonably within the control of the party whose performance is sought to be excused thereby, including (1) acts of God, strikes, lockouts, or other industrial disputes or disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, tornadoes, hurricanes, storms, severe winter weather, and warnings for any of the foregoing which may necessitate the precautionary shut-down of wells, plants, pipelines, the Facilities, truck unloading facilities; (2) failure of any parties downstream of the Delivery Point(s) (except for downstream parties that are Affiliates of Carrier) to timely install or provide interconnection or receipt facilities, or other related facilities; (3) floods, washouts, arrests and restraints of governments and people, civil disturbances, explosions, sabotage, breakage or accidents to equipment, machinery, plants, truck unloading facilities, other related facilities, or lines of pipe; (4) the making of repairs or alterations to lines of pipe, the Gathering System, truck unloading facilities, plants or equipment; (5) freezing of wells or lines of pipe; (6) electric power shortages; (7) necessity for compliance with any court order, or any law, statute, ordinance, regulation or order promulgated by a Governmental Authority having or asserting jurisdiction, unless such necessity arises as a result of Carrier’s or its Affiliates’ failure to comply with any Applicable Law (provided that Carrier shall be permitted to resist in good faith

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		the application to it of any such law by all reasonable legal means); (8) inability to obtain necessary permits, rights of way or materials for construction, maintenance or operations provided same were timely and diligently pursued; (9) inclement weather that necessitates extraordinary measures and expense to construct facilities or maintain operations; and (10) any other causes, whether of the kind enumerated herein or otherwise, not reasonably within the control of the Party claiming suspension, including any such cause or event occurring with respect to the facilities, services, equipment, goods, supplies or other items necessary to the performance of such party’s obligations hereunder. “Force Majeure” also includes any event of Force Majeure occurring with respect to the facilities or services of either party’s Affiliates or service providers providing a service or providing any equipment, goods, supplies or other items necessary to the performance of such party’s obligations hereunder.
31.	Gathering Fee	As defined in Section 2.1.4.
32.	Gathering System	As of the Effective Date: (i) crude oil pipelines and related facilities in Lipscomb and Hemphill Counties, Texas to enable Carrier to gather Crude Oil produced from the South Lipscomb Area at the CRPs to the Casey Station; and (ii) a 4” crude oil pipeline to receive Crude Oil at the Casey Station and deliver it to the Delivery Point(s).
33.	Governmental Authority	Any court, government (federal, tribal, state, local, or foreign), department, political subdivision, commission, board, bureau, agency, official, or other regulatory, administrative, or governmental authority.
34.	Governmental Authorizations	Any authorization, approval or permit from any national, regional, state, local or municipal government, or any political subdivision, agency, commission or authority thereof (including any maritime authorities, port authority or any quasi-governmental agency) having jurisdiction over a party or its Affiliates, the Facilities or any of the activities contemplated by this Tariff.
35.	Gravity	API Gravity.
36.	Interruption	As defined in Section 3.3.1.
37.	Line Fill and Tank Fill	The static quantity of Crude Oil needed to occupy the physical space within the Facilities required for Facilities operations.

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38.	Losses	All losses, liabilities, damages, claims, demands, fines, penalties, costs, or expenses, including reasonable attorneys’ fees and court costs.
39.	LUFs	As defined in Section 2.1.1.
40.	Month	A calendar month beginning at 12:01 am on the first Day of the calendar month and ending at 12:01 am on the first Day of the next calendar month.
41.	Nomination	A written offer or tender by a Shipper to Carrier of a stated quantity of Crude Petroleum for transportation from a specified CRP to a specified Delivery Point in accordance with this Tariff.
42.	Non-Dedicated Shipper	As defined in Section 2.2.
43.	Non-Dedicated Shipper Agreement	As defined in Section 2.2.
44.	Non-Dedicated Shipper Rate	As defined in Section 2.2.
45.	Person	Any individual, corporation, partnership, limited liability company, other business organization of any kind, association, trust, or governmental entity, agency, or instrumentality.
46.	Primary Term	As defined in Section 2.1.1.
47.	Prior Dedication	Any Crude Oil that has previously been dedicated to a Third Party prior to the effective date of the Dedicated Firm Shipper Agreement (or, for interests subsequently acquired, prior to the date of such acquisition).
48.	Priority Capacity	As defined in Section 3.5.2.
49.	Priority Capacity Rate	As defined in Section 2.1.4.
50.	Prorationed Capacity	As defined in Section 3.5.1.
51.	Proration	As defined in Section 3.4.1.

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52.	Quality Specifications	As defined in Section 3.1.
53.	Receiving Facilities	As defined in Section 3.1.
54.	RRC	The Commission.
55.	Rules and Regulations	As defined in the first paragraph.
56.	Shipper	The Person (and its heirs, successors, and permitted assignees) that executes and takes service from Carrier in accordance with this Tariff.
57.	Shipper Agreement	A Dedicated Firm Shipper Agreement or Non-Dedicated Shipper Agreement, as applicable.
58.	Shipper Crude Oil	Crude Oil delivered by Shipper or its Affiliates to a CRP in accordance with this Tariff.
59.	Tariff	As defined in the first paragraph.
60.	Third Party	Any Person other than Carrier, Shipper, or their respective Affiliates.
61.	Unloading and Transportation Fee	As defined in Section 2.1.4.
62.	Year	Any period consisting of 365 consecutive Days, commencing and ending at 7:00 a.m., prevailing Central Time; provided, that any year which contains the date of February 29 will consist of 366 consecutive Days.

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ATTACHMENT 2.4

CRPS AND DELIVERY POINTS

CRP Name:	Location:
Gathering Pipeline Receipt Points	the inlet flange of Carrier’s Facilities at the receipt points located along the Gathering System for the purpose of receiving Shipper’s Crude Oil.
Casey Station	the inlet flange of Carrier’s LUF at Casey Station
Osborn Station	the inlet flange of Carrier’s LUF at Osborn Station
Other	any other points mutually agreed upon in the future where Carrier receive Shipper’s Crude Oil

Delivery Point Name:	Location:
Valero Piper	the outlet flange of Carrier’s interconnection facilities at or near the Valero Piper Station in Lipscomb County, Texas
Osborn Station	the outlet flange of Carrier’s LUF at Osborn Station in Lipscomb County, Texas
Casey Station	the outlet flange of Carrier’s LUF at Casey Station
Other	any other points mutually agreed upon in the future where Carrier will redeliver Shipper’s Crude Oil

Monarch Texas RRC No.          , Attachment 2.4

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EXHIBIT F

QUALITY BANK POLICY

MONARCH OIL PIPELINE, LLC

QUALITY BANK

(a)General:

The purpose of the Gravity receipt and delivery quality bank (“Quality Bank”) is to mitigate material increases or decreases in each shipper’s respective Crude Oil value due to the commingling of Crude Oil in the Gathering System common stream.  The Quality Bank charges each shipper or pays each shipper dependent on the quality of the Gathering System common stream and the quality of each shipper’s Crude Oil.  Each shipper shall be required, as a condition of Tendering its Crude Oil, to participate in the Quality Bank.

API Gravity shall be the Crude Oil quality parameters used to determine the relative value of each shipper’s Crude Oil receipt and delivery stream in the Quality Bank.  For purposes of calculating the API Gravity of Crude Oil received, Crude Oil entering the Gathering System with an API Gravity of less than 45º shall be deemed to have an API Gravity of 45º.  The adjustment factor for Gravity shall be $0.30 per degree Gravity per Barrel for Crude Oil with an API Gravity less than or equal to 48.0º, $0.32 per degree Gravity per Barrel for Crude oil with an API Gravity that is greater than 48.0º and less than 55.0º, and $0.35 per degree Gravity per barrel for Crude oil with an API Gravity that is greater than or equal to 55.0º.

(b)Calculation of Quality Bank Credits/Debits:

(1)Gravity Receipts:

The weighted average Gravity differential value per Barrel shall be obtained in the following manner:

a.Multiply the Gravity times (x) the Gravity differential values per Barrel times (x) the number of Barrels to which such Gravity differential values are applicable;

b.Sum the Gravity values; and

c.Divide the total of the resultant Gravity differential values in dollars and cents by the total of the applicable Barrels.

Applicable Barrels and Gravities shall be the net Barrels at 60° Fahrenheit (with no deduction for loss allowance) and the Gravities recorded by the Gatherer at the CRPs.

(2)Adjustment between shippers for Gravity shall be computed as follows:

a.Compute the weighted average Gravity differential value per Barrel of the Barrels received from each shipper.

b.Compute the weighted average Gravity differential value per Barrel of the composite common stream receipts.

(i)If the weighted average Gravity differential value per Barrel of a shipper as so determined under Paragraph (b)(2)(a) above shall be greater than the weighted average Gravity differential value per Barrel of Gatherer’s common stream Crude Oil as determined under Paragraph (b)(2)(b), the difference in cents per Barrel shall be calculated and such shipper shall be debited an amount calculated by multiplying said difference in Gravity differential value per Barrel by the Applicable Barrels.

(ii)If the weighted average Gravity differential value per Barrel of a shipper is less than the weighted average Gravity differential value per Barrel of Gatherer’s common stream Crude Oil, the difference shall be calculated as above outlined and such shipper shall be credited for such difference.

(3)Gravity Deliveries:

The weighted average Gravity differential value per Barrel shall be obtained in the following manner:

a.Multiply the Gravity times (x) the Gravity differential values per Barrel times (x) the number of Barrels to which such Gravity differential values are applicable;

b.Sum the Gravity values; and

c.Divide the total of the resultant Gravity differential values in dollars and cents by the total of the applicable Barrels.

Applicable Barrels and Gravities shall be the net Barrels at 60° Fahrenheit (with no deduction for loss allowance) and the Gravities recorded by the Gatherer at the CRPs.

(4)Adjustment between shippers for Gravity shall be computed as follows:

a.Compute the weighted average Gravity differential value per barrel of the barrels delivered from each shipper.

b.Compute the weighted average Gravity differential value per Barrel of the composite common stream deliveries.

(i)If the weighted average Gravity differential value per Barrel of a shipper as so determined under Paragraph (b)(4)(a) above shall be Greater than the weighted average Gravity differential value

per Barrel of Gatherer’s common stream Crude Oil as determined under Paragraph (b)(4)(b), the difference in cents per Barrel shall be calculated and such shipper shall be credited an amount calculated by multiplying said difference in Gravity differential value per Barrel by the Applicable Barrels.

(ii)If the weighted average Gravity differential value per Barrel of a shipper is less than the weighted average Gravity differential value per Barrel of Gatherer’s common stream Crude Oil, the difference shall be calculated as above outlined and such shipper shall be debited for such difference.

(5) These calculations shall be made for each calendar Month and the algebraic sum of the adjustments for the System shall be zero ± One Dollar.  If a shipper shall have a net debit balance the balance shall be remitted by ACH or Wire Transfer to the clearinghouse within fifteen (15) days from receipt of statement of such debit.  If such shipper shall have a credit, the clearinghouse shall remit the amount thereof after receipt by the clearinghouse of the sums from those shippers having debits as calculated above.

(c)Administration:

All System shippers shall be required to participate in the Quality Bank.  Gatherer shall administer the Quality Bank and shall perform, or cause to be performed, the clearinghouse business of calculating and effecting adjustments using a process of debits, credits and interchange of funds among all shippers on the System.  Gatherer may subcontract any or all of the work associated with administration of the Quality bank, but by doing so Gatherer shall not be relieved of any of its obligations hereunder.

Gatherer shall perform the necessary Quality Bank calculations as soon as the data is available for such Month and promptly issue appropriate credit/debit statements to each shipper.

Gatherer shall be responsible for determining and/or securing the quality of Crude Oil received and delivered from each shipper for transportation in Gatherer’s System.

Gatherer shall administer the Quality Bank, or cause the Quality Bank to be administered, without profit or cost to Gatherer.

EX-10.35

Exhibit 10.35

AMENDED AND RESTATED MONARCH OIL PIPELINE, LLC

GATHERING AND TRANSPORTATION SERVICES AGREEMENT

THIS AMENDED AND RESTATED GATHERING AND TRANSPORTATION SERVICES AGREEMENT (“Agreement”), is made and entered into the 23rd day of October, 2015 (“Effective Date”) by and between MONARCH OIL PIPELINE, LLC, a Delaware limited liability company (“Monarch”), and Jones Energy, LLC, a limited liability company (“Shipper”).  Monarch and Shipper are each sometimes hereinafter individually referred to as a “Party” and together referred to as the “Parties”.

RECITALS:

1.Shipper and Monarch have entered into the Gathering and Transportation Services Agreement, dated as of September 26, 2014 (the “Original Agreement”).

2.Monarch intends to construct, own, and operate a pipeline gathering system with an initial projected capacity of 30,000 Barrels of Crude Oil per Day (“BPD”) that will transport Crude Oil from Central Receipt Point(s) (“CRPs”) in the South Lipscomb Area in Lipscomb County, Texas to the Casey Station in Section 161 in Lipscomb County, Texas (“Gathering System”); to construct, own, and operate the “Casey Station,” a facility located at the terminus of the Gathering System consisting of inlet meters (measuring all Crude Oil entering the Casey Station from the Gathering System), a minimum of four (4) automated truck unloading facilities, a minimum of 10,000 BPD of Crude Oil operational storage tank facilities, vapor recovery equipment, and a crude oil heater that may be utilized as necessary in the event Crude Oil is delivered that does not meet the specifications herein; and to construct, own and operate pipeline transportation facilities consisting of an 8-inch pipeline capable of transporting approximately 30,000 BPD of Crude Oil from the Casey Station to Plains Pipeline, LP’s (“Plains”) Reydon Station located in Roger Mills County, Oklahoma (“Transportation System”), which facilities collectively are referred to as the “Pipeline.”

3.The entirety of the Pipeline, when used by Shipper to transport Crude Oil from the CRP(s) to Plains is a “Common Carrier” subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), which regulates the interstate transportation of Crude Oil under authority set forth in the Interstate Commerce Act (“ICA”).

4.Shipper holds certain oil and gas leases located in Lipscomb and Hemphill Counties, Texas (as described on Exhibit B), and has Crude Oil production therefrom that it desires to have gathered and transported by Monarch on and through the Pipeline.

5.In exchange for Shipper’s commitment to ship Crude Oil produced from its oil and gas leases for a specified term, Monarch is willing to gather and transport a specified volume of Crude Oil for Shipper for a specified term and at a committed transportation fee on the Pipeline, subject to and upon the terms and conditions of this Agreement.

6.The Parties desire to amend and restate the Original Agreement in its entirety to read as set forth below.

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AGREEMENT

In consideration of the mutual covenants, promises and agreements in this Agreement, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

SECTION I

DEFINITIONS

A.The following capitalized terms used in this Agreement and the attached exhibits and schedules shall have the meaning set forth below:

i.“Actual Shipments” means the volumes of Crude Oil tendered by Shipper at the Receipt Point(s) for ultimate delivery to the Delivery Point(s) for the account of Shipper.

ii.“Affiliate” means any Person, corporation, partnership, limited partnership, limited liability company, or other legal entity, whether of a similar or dissimilar nature, which (i) controls, either directly or indirectly, a Party, or (ii) is controlled, either directly or indirectly, by such Party, or (iii) is controlled, either directly or indirectly, by a Person or entity which directly or indirectly controls such Party.  As used in this definition, “control” means the ownership of (or the right to exercise or direct) fifty percent (50%) or more of the voting rights in the appointment of directors of such entity, or fifty percent (50%) or more of the interests in such entity.

iii.“Agreement” shall have the meaning set forth in the initial paragraph.

iv.“API Gravity” or “Gravity” means Gravity determined in accordance with the ASTM International (formerly known as the American Society for Testing and Materials) (“ASTM”) Designation D-287-82 or the latest revision thereof.

v.“Applicable Law” means with respect to any Person, property or matter, any of the following applicable thereto: any statute, law, regulation, ordinance, rule, judgment, rule of common law, order, decree, governmental approval, concession, grant, franchise, license, agreement, directive, ruling, guideline, policy, requirement or other governmental restriction or any similar form of decision of, or determination by, or any interpretation, construction or administration of any of the foregoing, by any Governmental Authority, in each case as amended.

vi.“Area of Mutual Interest” or “AMI” means the areas depicted on Exhibit B and described as (i) “South Lipscomb” and located in Lipscomb and Hemphill Counties, Texas and a two (2) mile radius surrounding the South Lipscomb Area, and (ii) “Hemphill” and located in Hemphill County, Texas, and a two (2) mile

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radius surrounding the Hemphill Area, and from which Shipper’s Crude Oil is dedicated to this Agreement.

vii.“Barrel” or “bbl” means forty-two (42) gallons of 231 cubic inches per gallon at 60 degrees Fahrenheit (60° F).

viii.“BPD” shall have the meaning set forth in the Recitals.

ix.“BS&W” means basic sediment, water and other impurities.

x.“Business Day” means any day other than a Saturday, Sunday or other day on which banks in the State of Texas are permitted or required to close.

xi.“Casey Station” shall have the meaning set forth in the Recitals.

xii.“Central Receipt Point” or “CRPs” means inlet flange of Monarch’s facilities at the receipt points located along the Gathering System for the purpose of receiving Shipper’s Crude Oil, and any other points mutually agreed upon in the future at which Monarch will receive Shipper’s Crude Oil.  Each CRP shall be equipped with (i) automated communication equipment to allow for remote monitoring and control of Gathering System pumps at each such location and (ii) a LACT Unit. The CRPs are described on Exhibit F.

xiii.“Commencement Date” means the Pipeline’s in-service date which shall be the first Day of the Month following the date Monarch notifies Shipper that Monarch has obtained all required operating permits and/or necessary regulatory approvals and the required amounts of line and tank fill have been delivered by Shipper to Monarch in accordance with Monarch’s Tariff to the extent necessary to commence Crude Oil commercial service.

xiv.“Committed Rate” shall have the meaning set forth in Section VIII.A.

xv.“Committed Shipper” means a Shipper entering into this Agreement with Monarch, a pro forma version of which shall be made available in the open season that Monarch shall hold beginning Fourth Quarter, 2014 (“Open Season”), provided that Shipper commits a Dedication to the Pipeline for a set term in exchange for a Committed Volume, as set forth in Exhibit A to this Agreement.  A Committed Shipper may also be referred to herein as a “Dedicated Firm Shipper.”

xvi.“Committed Volume” means the maximum volume of Crude Oil (stated in BPD) that Monarch commits to gather and/or transport for Shipper in exchange for a Committed Shipper’s Dedication, as set forth in Exhibit A to this Agreement.

xvii.“Connection Timing Commitment” shall have the meaning set forth in Section VI.C.ii.

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xviii.“Crude Oil” means naturally occurring, unrefined petroleum product composed of hydrocarbon deposits of varying grades.

xix.“Day” means a period of twenty-four (24) consecutive hours commencing at 12:01 A.M. and ending at 12:00 A.M. prevailing Central Time.

xx.“Dedication” means Shipper’s dedication, subject to Section VI.A, to Monarch and/or its Affiliates, for the Term except and to the extent released hereunder, of all of Shipper’s recoverable Crude Oil or Shipper’s Affiliate’s recoverable Crude Oil produced from oil and gas wells located within the Area of Mutual Interest in which Shipper or its Affiliates now or hereafter owns, controls, acquires, and has the right to sell, market (as such marketing rights may change from time to time), or otherwise dispose of and that is not subject to a Prior Dedication as of the Effective Date (or, for subsequently acquired interests within the Area of Mutual Interest, that is not subject to a Prior Dedication as of the date of acquisition).  Shipper agrees that the entirety of Shipper’s Crude Oil subject to Shipper’s Dedication shall be delivered by Shipper to Monarch and/or its Affiliates either at the CRP(s) or at the automated truck unloading stations at the Casey Station or at the well site(s) as governed by the Intrastate Agreement where Monarch and/or its Affiliates shall receive the Crude Oil for its transportation in accordance with this Agreement.

xxi.“Delivery Point(s)” means the outlet flange of Monarch’s facilities at or near the Plains Reydon Station interconnect in Roger Mills County, Oklahoma and each point on Monarch’s System identified as a point where Monarch can deliver Crude Oil out of its System.  The Delivery Point(s) are described on Exhibit C.

xxii.“Disclosing Party” shall have the meaning set forth in Section XXII.A.

xxiii.“Excess Volume” shall have the meaning set forth in Section VI.B.i.

xxiv.“Expedited Temporary Release” shall have the meaning set forth in Section VI.A.v.b.

xxv.“Expedited Temporary Release Period” shall have the meaning set forth in Section VI.A.v.b.

xxvi.“Facilities” means the interstate Pipeline facilities described in the Recitals.

xxvii.“FERC” shall have the meaning set forth in the Recitals.

xxviii.“Force Majeure” shall have the meaning set forth in Section XVI.

xxix.“Gathering System” shall have the meaning set forth in the Recitals.

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xxx.“General Commodity Rate” means the rate paid by an Uncommitted Shipper to use the Pipeline.

xxxi.“Governmental Authority” means any court, government (federal, tribal, state, local, or foreign), department, political subdivision, commission, board, bureau, agency, official, or other regulatory, administrative, or governmental authority.

xxxii.“Governmental Authorizations” means any authorization, approval or permit from any national, regional, state, local or municipal government, or any political subdivision, agency, commission or authority thereof (including any maritime authorities, port authority or any quasi-governmental agency) having jurisdiction over a Party or its Affiliates, the Pipeline, or any of the activities contemplated by this Agreement pursuant to this Agreement.

xxxiii.“Hemphill Area” means the lands identified on Exhibit B as “Hemphill”.

xxxiv.“Information Receiving Party” shall have the meaning set forth in Section XXII.A.

xxxv.“Initial Committed Rate Period” shall have the meaning set forth in Exhibit A.

xxxvi.“Initial CRP(s)” means the 119 CRPs identified in Exhibit F.  For purposes of this Agreement, the locations specified on Exhibit F shall become Initial CRPs on the date at such time they become connected to the Gathering System.

xxxvii.“Interruption” and “Curtailment” shall have the meaning set forth in Monarch’s Rules and Regulations Tariff, or any successor thereto, which was filed initially in FERC Docket No. IS15-618.

xxxviii.“Interstate Commerce Act” shall have the meaning set forth in the Recitals.

xxxix.“Intrastate Agreement” shall have the meaning set forth in Section IV.D.

xl.“LACT Unit” means an oil industry standard lease automated custody transfer unit comprised of a Coriolis mass measurement meter and BS&W monitor, as well as other necessary controls.

xli.“Losses” means all losses, liabilities, damages, claims, demands, fines, penalties, costs, or expenses, including reasonable attorneys’ fees and court costs.

xlii.“Month” means a calendar month beginning at 12:01 am on the first day of the calendar month and ending at 12:01 am on the first day of the next calendar month.

xliii.“Monarch” shall have the meaning set forth in the introduction and shall include its heirs, successors, and assignees.

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xliv.“Ninety Percent Cap” shall have the meaning set forth in Section VI.A.ii.b.

xlv.“Notice(s)” shall have the meaning set forth in Section XXII.B.

xlvi.“Party” or “Parties” shall have the meaning set forth in the initial paragraph.

xlvii.“Person” shall be broadly interpreted to include, without limitation, any corporation, company, partnership, trust, governmental authority or individual.

xlviii.“Pipeline” shall have the meaning set forth in the Recitals.

xlix.“Plains” shall have the meaning set forth in the Recitals.

l.“Primary Point” means the Delivery Point(s) identified as a “Primary Point” on Exhibit A.

li.“Primary Term” shall have the meaning set forth in Section IV.A.

lii.“Prior Dedication” shall have the meaning set forth in Section VI.A.vii.

liii.“Proration” shall have the meaning set forth in Monarch’s Rules and Regulations Tariff, or any successor thereto.

liv.“Prorationed Capacity” shall have the meaning set forth in Section VII.A.

lv.“Receipt Point(s)” means the point at which Crude Oil is accepted into the Pipeline listed in Monarch’s Rates Tariff, or hereafter designated by Monarch.  The CRPs are Receipt Point(s) on Monarch’s Pipeline.

lvi.“Secondary Term” shall have the meaning set forth in Section IV.A.

lvii.“Services” shall mean the transportation of Crude Oil and other related services for Shipper’s account on the Monarch Pipeline from the Receipt Point(s) to the Delivery Point(s) as specified in Shipper’s nomination.

lviii.“Shipper” shall have the meaning set forth in the introduction and shall include its heirs, successors, and assignees.

lix.“Shipper’s Crude Oil” means the Crude Oil produced from oil and gas wells in which Shipper or its Affiliates owns or controls an interest and has the right to market.

lx.“South Lipscomb Area” means the lands identified on Exhibit B as “South Lipscomb” and located in Lipscomb and Hemphill Counties, Texas.

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lxi.“System” means the facilities, including the pipeline, tanks, pumps and other associated facilities that Monarch owns an interest in, and to which this TSA applies.

lxii.“Tariff” shall have the meaning set forth in Section V.

lxiii.“Term” shall have the meaning set forth in Section IV.A.

lxiv.“Temporary Release” shall have the meaning set forth in Section VI.A.v.

lxv.“Total Average Daily Delivered Volumes” shall mean the average quantity of Barrels of Crude Oil delivered each Day to the Delivery Point(s) and to all delivery points connected to the Gathering System off of pipelines owned by Monarch and/or its Affiliate(s), by Shipper during a consecutive three (3) Month period (excluding any Temporary Release periods); except that, for the fourth (4th), fifth (5th), and sixth (6th) Months following the Commencement Date, the Total Average Daily Delivered Volumes shall be based on the average quantity of Barrels of Crude Oil delivered each Day to the Delivery Point(s) and to all delivery points connected to the Gathering System off of pipelines owned by Monarch and/or its Affiliate(s) by Shipper during a one (1) Month period (excluding any Temporary Release periods).

lxvi.“Transportation System” shall have the meaning set forth in the Recitals.

lxvii.“Treating Fee” shall have the meaning set forth in Section IX.A.

lxviii.“Uncommitted Shipper” means a shipper that is not a Committed Shipper.

lxix.“Uneconomic” shall have the meaning set forth in section IV.B.

B.Rules of Interpretation

i.Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant hereto.

ii.As used herein, and in any certificate or other document made or delivered pursuant hereto, (i) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (ii) the word “incur” shall be construed to mean incur, create, issue, assume, become liable in respect of or suffer to exist (and the words “incurred” and “incurrence” shall have correlative meanings), and (iii) references to agreements or other contracts shall, unless otherwise specified, be deemed to refer to such agreements or contracts as amended, supplemented, restated or otherwise modified from time to time.

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iii.The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.

iv.The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

SECTION II

REQUEST FOR SERVICE

In exchange for Shipper’s Dedication, Shipper hereby requests that Monarch provide gathering and transportation services so that Shipper’s Crude Oil may move over and through the Pipeline from the Receipt Point(s) to the Delivery Point(s).

SECTION III

AGREEMENT TO PROVIDE SERVICE

A.In consideration of the terms and conditions herein and in response to such request, Monarch agrees, subject to Applicable Law and any applicable termination rights set forth herein, to provide interstate gathering and/or transportation service of Crude Oil from the Receipt Point(s) to the Delivery Point(s).

B.Execution of this Agreement, without material modification, provides sufficient commercial justification for the Pipeline project to move forward.  Shipper acknowledges that non-material modifications may be necessary as a result of the Open Season process, to be consistent with FERC policy.  If the FERC requires modifications to the Agreement, then the Parties shall negotiate in good faith to revise necessary elements of the Agreement in order to satisfy applicable FERC requirements.

C.Additional Open Season.  Monarch shall have the right, but not the obligation, to conduct additional open seasons for the Pipeline in order to contract with new or existing shippers for uncommitted or expansion capacity or capacity that has been made available due to the termination or expiration of Pipeline transportation services agreements.

SECTION IV

TERM

A.This Agreement shall commence on the Commencement Date and continue in effect for a period of ten (10) years (the “Primary Term”).  Thereafter, the Agreement shall automatically renew for consecutive one year periods (each, a “Secondary Term” and together with the Primary Term, the “Term”).  Either Party may terminate this Agreement

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by written Notice to the other Party not less than one (1) year prior to expiration of the Primary Term or any Secondary Term.

B.Monarch reserves the right, on a not unduly discriminatory or preferential basis, to reject or seek renegotiation of the terms under which Monarch shall continue the gathering of Shipper’s Crude Oil on the Gathering System should Monarch determine that gathering Shipper’s Crude Oil at any CRP becomes Uneconomic because of insufficient volume, or if all or part of Monarch’s Gathering System receiving Shipper’s Crude Oil becomes Uneconomic to operate, maintain, or repair because of the delivery of insufficient volumes of Crude Oil.  Monarch has the right to deem a CRP and any associated part of the Gathering System “Uneconomic” if the average BPD over a ninety (90) Day period at a particular CRP is less than twenty (20) BPD for a CRP with one production well behind the CRP and thirty (30) BPD for a CRP with more than one production well behind the CRP; provided, however, that no Initial CRP or any part of the Gathering System connecting the Initial CRPs to the Delivery Point(s) as of the Commencement Date, as such Gathering System and Initial CRPs are set forth on Exhibit F, shall ever be deemed Uneconomic during the Primary Term. In the event of a CRP or part of the Gathering System being declared Uneconomic, Monarch shall have the right to suspend receipt of a Shipper’s Crude Oil at that CRP or part of the Gathering System, without liability as long as such condition exists, by giving Shipper ninety (90) Days advance written Notice of such suspension.  During the ninety (90) Day Notice period, the Parties agree to meet to discuss and negotiate in good faith new terms for the applicable CRP or part of the Gathering System under which Monarch would continue to gather Shipper’s Crude Oil for transportation on the Gathering System. If the Parties are unable to reach agreement as to a remedy to such condition within thirty (30) Days of the end of the Notice period, either Shipper or Monarch may cause the CRP(s) or part(s) of the Gathering System in question and any part of the Dedication intended for delivery to such CRP(s) or part(s) of the Gathering System shall be permanently released from this Agreement.

C.During any Secondary Term, in the event Monarch declares all or part of Monarch’s Gathering System Uneconomic, Monarch shall have the right to suspend operations of the Gathering System or the affected part thereof without liability as long as such condition exists by providing Shipper with ninety (90) Days advance written Notice of the suspension. The Parties agree to meet within fifteen (15) Days after receipt of such Notice to discuss and negotiate in good faith alternative terms to remedy such Uneconomic Gathering System condition. If the Parties are unable to reach agreement as to a remedy to such condition within thirty (30) Days of the end of the Notice period, Monarch may elect to terminate gathering operations with respect to all of its Gathering System if it has been declared Uneconomic or such part as has been declared Uneconomic and shall provide Shipper thirty (30) Days prior written Notice of its intent to terminate such operations.  If Monarch terminates all or part of its gathering operations pursuant to this Section IV.C, either Shipper or Monarch shall have the right to and may so cause the Dedication impacted by such termination to be permanently released from this Agreement.

D.Notwithstanding anything to the contrary in Sections IV.B or IV.C, Monarch shall have the right to take a LACT unit out of service at a particular CRP and remove such CRP

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from this Agreement, pursuant to the terms set forth in the Amended and Restated Firm Crude Oil Gathering and Transportation Agreement dated October 23, 2015 (“Intrastate Agreement”).  Promptly after removing any such CRP in accordance with this Section IV.D, Monarch shall amend Exhibit F to reflect the removal of such CRP from this Agreement.  All non-pipeline and trucking activities for Shipper’s Crude Oil from the CRPs listed on Exhibit F and any non-CRP-connected wells located within the AMI shall be governed by the Intrastate Agreement.

SECTION V

MONARCH FACILITY OBLIGATIONS

A.Monarch will operate the Pipeline, to the extent it provides service in interstate commerce, as an interstate common carrier oil pipeline as defined by the Interstate Commerce Act.

B.Monarch shall use commercially reasonable efforts to place the Pipeline in service by November 1, 2015.  If the Pipeline is not in service by November 1, 2015, then Shipper shall have the right to contract for alternative transportation of Shipper’s Crude Oil for consecutive ninety (90) Day periods until such time as the Pipeline is in service, provided that if the Pipeline goes in service during one such ninety (90) Day period, Shipper shall have no obligation to transport Shipper’s Crude Oil on the Pipeline until the expiration of that ninety (90) Day period.

C.Prior to the Commencement Date, Monarch shall file with FERC a tariff applicable to pipeline gathering and transportation under this Agreement containing the rules and regulations governing the gathering and transportation of Crude Oil in the Pipeline and a tariff governing the gathering and transportation rates (collectively “Tariff,” which shall include any and all supplements thereto and successive issues thereof).  All shipments of Crude Oil on the Pipeline by Shipper shall be governed by the Tariff and all applicable statutes, rules and regulations governing common carrier pipelines and related facilities; provided, however, that this understanding shall not be deemed to lessen or impair any of Shipper’s obligations hereunder.  Shipper expressly agrees to abide by the terms of the Tariff.  Monarch may revise the Tariff from time to time, so long as such revisions do not materially conflict with the terms of this Agreement.  To the extent there is any conflict between the provisions of the Tariff and the terms of this Agreement, the terms of the Tariff shall govern.

SECTION VI

TRANSPORTATION SERVICES

A.Dedication Obligations.

i.In exchange for Shipper’s Dedication, Shipper shall become a Committed Shipper and shall have a priority right to its Committed Volume at the Committed Rate.

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Only Shipper’s Crude Oil shall be eligible for shipment as part of Shipper’s Committed Volume.

ii.A Dedicated Firm Shipper shall be permitted to adjust its Committed Volume subject to the following conditions:

a.After the first five (5) years of the Primary Term, Monarch will annually downward adjust a Dedicated Firm Shipper’s Committed Volume based upon 120% of Shipper’s deliveries of Barrels of Crude Oil to the Pipeline averaged for the immediate prior calendar year, if applicable based upon Shipper’s deliveries of Crude Oil in the prior calendar year.

b.After the first five (5) years of the Primary Term, if capacity is available, a Dedicated Firm Shipper will be permitted to adjust its Committed Volume upward based upon 120% of Shipper’s deliveries of Barrels of Crude Oil to the System averaged for the immediate prior calendar year, provided that the aggregate Committed Volumes of Committed Shippers cannot exceed ninety percent (90%) of the normal operating capacity of the Pipeline (“Ninety Percent Cap”).  If Monarch receives a request from a single Dedicated Firm Shipper, and such request would result in Monarch exceeding the Ninety Percent Cap, Monarch will allocate the requested volume to the single Dedicated Firm Shipper up to the level that reaches the Ninety Percent Cap.  If Monarch receives simultaneous upward adjustment requests from two or more Dedicated Firm Shippers, and such requests would result in Carrier exceeding the Ninety Percent Cap, Monarch will allocate such upward adjustment volume requests pro rata to each of the Dedicated Firm Shippers in accordance with the increased volume each such Dedicated Firm Shipper elects to adjust, not to exceed the Ninety Percent Cap in aggregate.  Notwithstanding anything to the contrary in this provision, Monarch may accept an upward adjustment request that exceeds the Ninety Percent Cap upon agreement by Monarch to undertake and complete an expansion of its Pipeline, and the volume of such upward adjustment that exceeds the Ninety Percent Cap will become part of such Dedicated Firm Shipper’s Committed Volume effective on the date such expansion is completed and available for service.  Any upward adjustment to a Dedicated Firm Shipper’s Committed Volume will take effect on first day of the Month following the adjustment request.

iii.Shipper warrants that it has the authority to make such Dedication.  Shipper covenants that (i) no subsequent transfer of any interest in the AMI shall be made without being made subject to this Dedication obligation, as set forth in Section VI.A.vii and (ii) prior to the effectiveness of any such transfer, Shipper shall provide to Monarch transferee’s acknowledgement of this Dedication.

iv.Shipper reserves the following rights: (i) to operate the wells producing from the AMI as a reasonably prudent operator; (ii) to operate separation and tankage

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facilities on the well site at surface production facilities on or well the well(s) producing from the AMI; (iii) to pool, communitize, or unitize Shipper’s interests in the AMI; (iv) to use Crude Oil for lease operations (excluding any type of major secondary or tertiary recovery projects); and (v) to distribute Crude Oil in-kind to various third parties as required by contractual obligations of Shipper in effect prior to the date hereof (or, for any later acquired interests, prior to the date of the acquisition), including lessors and royalty owners as required by the applicable provisions of any such oil and gas lease.

v.During any event(s) of Force Majeure as defined in Section XVI herein, Extended Force Majeure Event, Prorationed Capacity, or Interruption and Curtailment affecting  Monarch’s ability to accept Shipper’s Dedication for a period in excess of  seven (7) Days, Shipper shall have a temporary release from this Dedication, but only for those Barrels: (1) not accepted by the Gathering System or Transportation System; or (2) intended for delivery to the Receipt Point(s) affected by such Force Majeure, Extended Force Majeure Event, Prorationed Capacity or Interruption and Curtailment (“Temporary Release”); except that, if the cause of any event(s) of Force Majeure, Extended Force Majeure Event, Prorationed Capacity, or Interruption and Curtailment is due solely to the individual or collective gross negligence of Shipper and/or any Affiliate, agent, or subcontractor thereof, Shipper shall be granted a Temporary Release, but shall be required to pay Monarch the Committed Rate as though the Barrels subject to the Temporary Release constituted Actual Shipments over and through the Gathering System and/or Transportation System, a notarized accounting of which shall be provided to Monarch within fifteen (15) Days of Shipper resuming deliveries to the Gathering System and/or Transportation System following the end of such Temporary Release.

a.For the duration of any such Temporary Release, Shipper will be free to dispose of released Crude Oil volumes under other arrangements in Shipper’s sole discretion, provided that Shipper shall make commercially reasonable efforts to sell Shipper’s released Crude Oil volumes to the owner of the pipeline(s) immediately downstream of the Delivery Point(s), and/or its affiliates.  To the extent Shipper was able to sell Shipper’s released Crude Oil volumes to the owner of the pipeline(s) immediately downstream of the Delivery Point(s), and/or its affiliates, Shipper shall resume deliveries of released Crude Oil volumes to the Gathering System or Pipeline no later than the third (3rd) Day following delivery of Notice by Monarch stating that the Force Majeure, Extended Force Majeure, Prorationed Capacity, or Interruption and Curtailment has ended and Monarch is able to accept delivery of all such released volumes.  For all other temporarily released volumes, Shipper’s temporary release from the Dedication shall end, and Shipper shall resume deliveries of released Crude Oil volumes to the Gathering system or Transportation System, no later than the first (1st) Day of the fourth (4th) month following delivery of Notice by Monarch stating that the Force Majeure, Extended Force

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Majeure, Prorationed Capacity or Interruption and Curtailment has ended and Monarch is able to accept delivery of all such released volumes of Shipper’s Crude Oil.

b.Notwithstanding the requirements in Section VI.A.v, above, Shipper’s Temporary Release shall commence prior to the expiration of the seven (7) Day period if waiting the full seven (7) Days will cause Shipper to shut in production wells within the AMI and expediting the release is the only way to avoid the shut in (“Expedited Temporary Release”).  The Expedited Temporary Release period shall last only until the expiration of the seven (7) Day waiting period set forth in Section VI.A.v (“Expedited Temporary Release Period”).  Shipper may sell its Crude Oil at the affected CRP(s) or at the Casey Station to third-parties through the end the Expedited Temporary Release period only.  The provisions in Section VI.A.v.a, above, shall not apply until the Expedited Temporary Release Period has expired.  Shipper shall provide Notice to Monarch prior to releasing Shipper’s Crude Oil in an Expedited Temporary Release.  The Notice shall state that the release meets the criteria of this Section VI.A.v.b for an Expedited Temporary Release.

vi.Within twenty-one (21) Days of any event(s) of Force Majeure or Interruption and Curtailment affecting Monarch’s ability to accept Crude Oil produced from Shipper’s Dedication, Monarch shall provide Shipper with Notice to the extent Monarch anticipates such event(s) will last longer than one hundred and eighty (180) Days (the “Extended Force Majeure Event”).  Monarch’s notification shall include a good faith estimate of the length of the Extended Force Majeure Event and when Monarch anticipates it again will be able to accept Crude Oil produced from Shipper’s Dedication. Shipper and Monarch will work together in good faith to find alternative gathering and/or transportation services for Crude Oil produced from Shipper’s Dedication and affected by the Extended Force Majeure Event.  The term of any such alternative gathering and/or transportation service agreement must end no later than the first (1st) Day of the second (2nd) full or calendar Month following Monarch’s notification’s estimated end date for the Extended Force Majeure Event.

vii.The Dedication does not include any Crude Oil that has previously been dedicated to another pipeline or market prior to the Effective Date (or in the case of subsequently acquired interests, prior to the date of such acquisition) (the “Prior Dedication”).  Shipper shall not extend marketing or transportation agreements governing Crude Oil subject to a Prior Dedication(s) beyond the end of the longest primary contract term associated with the transportation and/or marketing of that particular Crude Oil. Upon termination of such agreements, all Crude Oil subject to the Prior Dedication(s) shall be deemed part of Shipper’s Dedication hereunder for the remaining Term of this Agreement.

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viii.If any Shipper transfers any right, title, or interest in the Dedication, such transfer shall be made subject to this Agreement and any such transfer shall not impair the Dedication herein to Monarch.  Shipper shall notify Monarch of any such transfer within ten (10) Business Days of the effective date thereof.  Shipper shall notify in writing any transferee that such acreage remains dedicated to Monarch pursuant to this Agreement and Shipper shall ensure that any such transfer is accompanied with appropriate contractual language requiring the transferee to deliver Crude Oil subject to the Dedication to Monarch during the Term of and in accordance with this Agreement.  Any such transfer or Shipper’s failure to notify Monarch thereof shall not impair Monarch’s rights under this Agreement as against Shipper; provided that Monarch shall release and waive any rights under this Agreement it may have against Shipper if and to the extent the transferee enters into an agreement with Monarch on substantially the same terms as those provided herein in respect of the transferred rights, title or interest in Crude Oil subject to the Dedication.

ix.If Shipper transfers any right, title, or interest in some, but not all of the Dedication, in addition to the requirements of VI.A.viii above, any right, title, or interest retained by Shipper shall remain subject to this Agreement and the Dedication, and Shipper’s Committed Rate and right to make a Priority Capacity Election, as set forth in Exhibit A to this Agreement, shall not be affected by the transfer.  All of Shipper’s right, title, or interest in Crude Oil subject to the Dedication will continue to be subject to the Dedication and Shipper’s Committed Volume and Committed Rate will remain unchanged.

x.On thirty (30) Days prior written Notice, Monarch shall have the right at its expense, at reasonable times during business hours, to audit the books and records of Shipper to the extent necessary to verify the accuracy of any statement or representation of Shipper related to Shipper’s Dedications, Prior Dedications or other prior obligations.

B.Rights to Unutilized Capacity

i.Subject to available capacity, Shipper shall have the right during each Month of the Term, but not the obligation, to ship Shipper’s Crude Oil in excess of Shipper’s Committed Volume (“Excess Volume”) at its Committed Shipper rate.  Monarch agrees to transport such Excess Volume subject to available capacity and the provisions set forth in Monarch’s Tariff including, but not limited to, Monarch’s prorationing provisions.  If Shipper delivers any quantities of Crude Oil that do not constitute Shipper’s Crude Oil, it shall nominate those quantities separately, and Monarch is only obligated to gather and/or transport those quantities subject to available capacity at the General Commodity Rate.

ii.Shipper agrees that, to the extent it does not utilize its Committed Volume in any Month, Monarch may utilize such unused capacity for the provision of Services to other shippers without impacting the payment or Dedication obligations of

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Shipper under this Agreement.  Any unused Committed Volume will be made available on a first-come, first-serve basis for Committed Shippers’ Excess Volume prior to being made available subject to the rules and regulations in Monarch’s Tariff.

C.Provision of Services

i.Subject to the terms and conditions of this Agreement and to the extent permitted by Applicable Law, Monarch agrees, as of the Commencement Date and continuing thereafter during the Term, to receive each Month from Shipper volumes of Crude Oil at the Receipt Point(s), as properly nominated and tendered by Shipper, up to Shipper’s Committed Volume and to redeliver equivalent volumes of Crude Oil to Shipper at one or more of the Delivery Point(s).  To the extent Shipper has a contractual obligation to sell Shipper’s Crude Oil to Plains at one or more of the Primary Point(s) beginning on the Commencement Date, Shipper agrees to transport through Monarch’s Facilities to the Primary Point(s) at least sixty-five percent (65%) of such Crude Oil volumes governed by that agreement.

ii.Monarch agrees to connect to the Gathering System any future newly-drilled wells drilled by Shipper within the South Lipscomb Area and located within one (1) mile of the Gathering System, within five (5) Days of completion of any such well, and prior to first production, subject to events of Force Majeure (the “Connection Timing Commitment”).  The Connection Timing Commitment will only apply to wells for which Shipper notifies Monarch of the completion date at least forty-five (45) Days in advance of completion.  In the event that Shipper does not notify Monarch at least forty-five (45) Days in advance of the completion date for a well, then Gatherer will commit to connecting the new well within forty-five (45) Days of receiving the Notice from Shipper.  Monarch may, in its sole discretion connect any future newly-drilled well located further than one (1) mile from the Gathering System (or received by truck Shipper’s Crude Oil produced from such well and transport and deliver such Shipper’s Crude Oil at its own expense as provided in the Intrastate Agreement), provided that Monarch has no obligation connect or receive from such well as set forth above in this sentence, then the Parties may negotiate in order to attempt to reach mutually agreeable terms to connect such well under an alternate fee structure and the Parties will amend this Agreement to memorialize any such agreement.  If the Parties are unable to mutually agree on terms to connect any future newly-drilled well located in the AMI and subject to the Dedication in accordance with the foregoing, then Shipper shall deliver Shipper’s Crude Oil produced from such well to the Casey Station, or an Affiliated system point, as applicable, by means other than through the Gathering System for further transportation on facilities owned and operated by Monarch and/or its Affiliates.

iii.Monarch’s duty to provide Services under this Section VI.C shall be subject to the provisions of the Tariff.  In addition, Monarch may refuse to accept any Barrels of

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Crude Oil from Shipper for Services if Shipper is in violation of the Tariff or if Shipper is in breach of this Agreement at the time the volumes of Crude Oil are tendered to Monarch.

D.This Agreement does not govern any commercial storage services.  Monarch has working tanks that are needed by Monarch to transport Crude Oil, but has no other tanks and, therefore, does not have facilities for rendering, nor does it offer, a commercial storage service.  Monarch will use its operational storage facilities, as necessary, to manage the Pipeline to allow for the gathering and transportation of Shipper’s Crude Oil pursuant to Shipper’s confirmed nominations for transportation to the Delivery Point(s).  Monarch will not accept for gathering or transportation any Crude Oil volumes for which Shipper has not made the necessary arrangements for shipment beyond the Delivery Point(s) or has not provided the necessary facilities for receiving said Crude Oil as it arrives at the Delivery Point(s).  Provisions for storage during transit in facilities furnished by Shipper at points on Monarch’s system will be permitted to the extent authorized by Monarch.

SECTION VII

PRIORITY CAPACITY ELECTION

A.Monarch will follow a Proration policy as set forth in the Tariff when the amount of Crude Oil nominations properly submitted by all system shippers exceeds the Pipeline’s capacity for a given Month.  The capacity available for service during the Month of allocation (design capacity less any reduction in capacity because of Interruption and Curtailment or Force Majeure as defined in the Rules and Regulations Tariff) is the “Prorationed Capacity.”

B.Monarch will maintain ninety percent (90%) of the Prorationed Capacity for a Committed Shipper Priority Capacity Election program.  Shipper is eligible to make a Priority Capacity Election should the Pipeline enter into a period of Proration.  Subject to reduced Pipeline capacity (as a result of, for example, Interruption and Curtailment or Force Majeure), Priority Capacity will be available to Shipper during periods of proration up to the level of Shipper’s Committed Volume for Shipper’s Crude Oil.  Shipper may elect and secure Priority Capacity by paying a one cent ($0.01) per Barrel premium over the General Commodity Rate set forth in the Tariff.  In the event that the Prorationed Capacity is less than design capacity (as a result of, for example, Interruption and Curtailment or Force Majeure), the Priority Capacity available for each Committed Shipper will be allocated pro rata in accordance with each Committed Shipper’s respective Committed Volume.

SECTION VIII

TARIFF RATES AND CHARGES

A.Committed Rate.  The “Committed Rate” is the rate per Barrel that Shipper agrees to pay for its Actual Shipments of Committed Volumes during the Term, as that rate may be

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changed from time to time during the Term in accordance with the provisions of this Agreement.  The Committed Rate that Shipper agrees to pay as of the Commencement Date is set forth in Exhibit A attached hereto.  The Committed Rate will be published in Monarch’s Tariff and shall at all times be less than the General Commodity Rate, except when Shipper makes a Priority Capacity Election, and at those times, only to the extent necessary to secure capacity in excess of the capacity to which Shipper is entitled by operation of the Proration policy in the absence of a Priority Capacity Election.  The Committed Rate is not required to be cost-based to meet a statutory “just and reasonable” standard as long as the rate is set in a manner that is not unduly preferential or discriminatory.

B.Excess Volumes. Shipper shall pay the Committed Rate then applicable to Shipper for any Excess Volumes above its Committed Volume that Shipper ships in a Month.

C.General Commodity Rate.  Shipper shall pay the General Commodity Rate for any Barrels that Shipper ships in a Month that do not constitute Shipper’s Crude Oil.

D.Settlement Rates. To the extent permitted by Applicable Law, Monarch may, at its election, file the Committed Rate, including the initial Committed Rate and any subsequent changes thereto pursuant to the terms of this Agreement, as Settlement Rates in the Rates Tariff under 18 C.F.R. § 342.4(c) and Shipper expressly agrees to support such filings.

E.Fees and Charges of General Application.  Shipper shall be subject to fees and charges set forth in the Tariff.

F.Monarch shall have the right to adjust the rates set forth herein, including the Committed Rates, each July 1 in accordance with FERC indexing methodology as described in 18 C.F.R. § 342.3, subject to the following qualifications.  In a given index year (July 1 through June 30), Monarch’s maximum annual rate adjustment shall be the lesser of (a) the generally applicable index adjustment as published by FERC for that given index year and (b) three percent (3%).  In the event that application of the generally applicable index adjustment as published by FERC for a given index year would result in a rate decrease, Monarch shall not be required to decrease its rates by more than three percent (3%).  Any such rate adjustment shall be prorated for the first index year Monarch is in service by multiplying (i) the lesser of the index adjustment or three percent (3%) by (ii) a fraction, the numerator of which is the number of Days between the Commencement Date and June 30 of the index year and the denominator of which is 365.  The Committed Rate shall never be lower than the rate agreed to in this Agreement, as set forth in Exhibit A to this Agreement.

SECTION IX

NOMINATIONS, QUALITY, AND PRORATIONING

A.Nominations.  Shipper shall follow the nomination procedures set forth in the Tariff.

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B.Quality.  Quality provisions in the Tariff, or its successor, shall be applicable to the Crude Oil delivered by Shipper.  Shipper acknowledges that Shipper’s Crude Oil may be commingled with other Crude Oil produced by third parties and that the Crude Oil delivered by Monarch at the Delivery Point(s) will not necessarily be the identical Crude Oil delivered by Shipper at the Receipt Point(s).  Monarch agrees to keep Shipper whole should commingling result in a deviation in Shipper’s average Gravity delivered to the Pipeline through implementation of a Quality Bank as set forth in Monarch’s Rules and Regulations Tariff.  Shipper agrees to a Crude Oil “Treating Fee” in the event Shipper delivers out of spec Crude Oil which contaminates the Pipeline, as set forth in the Rules and Regulations Tariff.  Monarch’s obligation to treat Shipper’s Crude Oil is limited to the use of Facilities described in this Agreement.  Monarch is not obligated to purchase or construct any such additional facilities after the Commencement Date to treat Shipper’s Crude Oil.

C.Line Fill and Tank Fill.  The Line Fill and Tank Fill provisions in Monarch’s Rules and Regulations Tariff, or its successor, shall be applicable to the Crude Oil delivered hereunder.

D.Prorationing.  Capacity on the Monarch Pipeline shall be allocated in accordance with Monarch’s Rules and Regulations Tariff or its successor.

SECTION X

MEASUREMENT, MANAGEMENT, CUSTODY, AND RISK OF LOSS OF CRUDE OIL

A.Monarch and Shipper shall measure Crude Oil delivered hereunder as provided in accordance with Monarch’s Rules and Regulations Tariff and pursuant to the Quality Bank set forth in Monarch’s Rules and Regulations Tariff.

B.Control and possession of the Crude Oil received under this Agreement shall pass from Shipper to Monarch at the Receipt Point(s).

C.Control and possession of the Crude Oil delivered under this Agreement shall pass from Monarch to Shipper at the Delivery Point(s).

D.Each Shipper shall be allocated a pro-rata share of actual volumetric losses incurred on the Pipeline due to evaporation, measurement, and other losses in transit (“Line Loss” or “Pipeline Loss Allowance) Pipeline adjustments will be made on the basis of total quantities received and will be assessed at the CRP(s).

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SECTION XI

DUTY TO SUPPORT

A.Shipper’s Duty to Support Prior to Commencement Date.  To the extent not inconsistent with Applicable Law, Shipper hereby agrees prior to the Commencement Date: (a) to reasonably support and cooperate — and not to oppose, obstruct or otherwise interfere in any manner, direct or indirect — with the efforts of Monarch to obtain all governmental, regulatory and other authorizations and approvals necessary for the construction and operation of the Pipeline in the form and manner proposed by Monarch; ; and (b) to not take, directly or indirectly, any action that (i) is designed to delay review or approval of any petitions or applications to any Governmental Authorities related to the Pipeline, or (ii) would materially and adversely affect the Pipeline or this Agreement.  Notwithstanding the foregoing, nothing herein shall prevent Shipper from (i) protesting any regulatory or other filings that are in conflict with the terms of this Agreement, and (ii) proceeding in any manner consistent with Applicable Law if this Agreement is terminated or if the Pipeline has been abandoned by Monarch.

B.Shipper’s Duty to Support Tariff Filings.  To the extent consistent with Applicable Law, Shipper hereby agrees during the Term of this Agreement not to protest, complain, or take any action, nor recommend or cause any affiliated entity or other entity to protest, complain, or take any action, that is designed to or may delay review or approval of the filing of the Tariff, including the Committed Rate, with FERC or any other governing body, unless such tariff filings are in conflict with the terms of this Agreement.

SECTION XII

EVENTS OF DEFAULT

A Party becomes a “Defaulting Party” and the following actions shall constitute “Default” if the Defaulting Party shall (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it; (iii) otherwise become bankrupt or insolvent (howsoever evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee or other similar official appointed with respect to it or substantially all of its assets; or (vi) consolidate or amalgamate with, or merge with or into, or transfer all or substantially all of its assets to another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all of the obligations of the Party under this Agreement by operation of law or pursuant to another agreement reasonably satisfactory to the other Party (“Non-Defaulting Party”), then the Non-Defaulting Party, in addition to any and all other remedies available hereunder or pursuant to law, shall have at its sole election and upon Notice thereof to the Defaulting Party, the right to immediately withhold, refuse or suspend performance under this Agreement or the Tariff and the right to terminate this Agreement by designating in any such Notice the effective date of termination (which effective date of termination shall not be earlier than the Day such Notice is given and not later than twenty (20) Days after such Notice is given).

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SECTION XIII

ADEQUATE ASSURANCES

If at any time Shipper assigns the Agreement in connection with the sale of all or substantially all of its assets, or in connection with a merger, consolidation, or other reorganization, at the time of and following such assignment, by Notice to Shipper, Monarch may require any of the following (individually and collectively, “Adequate Assurance”) prior to Monarch’s obligation to continue to provide services hereunder:  (1) prepayment of estimated Fees to be held by Monarch without interest accruing thereon in advance of a delivery month; (2) a cash deposit in an amount satisfactory to Monarch; (3) a letter of credit at Shipper’s expense in an amount and from a financial institution satisfactory to Monarch; or (4) a guaranty in an amount and from a third party acceptable to Monarch.  Shipper shall provide such Adequate Assurance within two (2) Business Days of demand therefore.

SECTION XIV

TAXES

Shipper shall pay or cause to be paid, and agrees to indemnify and hold harmless Monarch from and against the payment of, all excise, gross production, severance, sales, occupation, and all other taxes; and all charges, or impositions of every kind and character required by statute or by any Governmental Authority with respect to Shipper’s Crude Oil (other than margin or franchise taxes or taxes imposed upon income, profits or gains of Monarch) and the handling thereof prior to receipt by Monarch. Monarch shall pay or cause to be paid all taxes and assessments, if any, imposed upon Monarch for the activity of gathering and/or transporting Shipper’s Crude Oil after receipt and prior to its redelivery by Monarch at the Delivery Point(s). Neither Party shall be responsible or liable for any taxes or other statutory charges levied or assessed against the facilities of the other Party used for the purpose of carrying out the provisions of this Agreement. Shipper shall indemnify and save Monarch harmless from and against all loss, cost, damage, and expense of every character and in kind resulting from any adverse claims made with respect to all Crude Oil, royalties, taxes, payments or other charges, and Monarch has the right to suspend its receipt of any of Shipper’s Crude Oil subject to such claims until they are resolved to Monarch’s satisfaction.

SECTION XV

LAWS AND REGULATIONS

A.The Parties acknowledge that the Pipeline is subject to regulation by FERC and may be subject to regulation by other Federal or State agencies with jurisdiction over the facilities to be constructed and the transaction contemplated by this Agreement, or any of their successors. The Parties agree to comply with all such Applicable Laws, rules and regulations.

B.The Parties acknowledge that Monarch is a common carrier for hire, and this Agreement and all gathering and transportation services performed by it on the Gathering System

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and/or Transportation System for Shipper pursuant to this Agreement in interstate commerce, shall be subject to the rules and regulations in Monarch’s Tariff and its successors; provided, as between Monarch and Shipper, if there is a conflict between the terms and conditions of this Agreement and the Tariff, the Tariff will govern and control. Monarch shall be responsible for filing with FERC all necessary tariffs and/or amendments to the Tariff in order to provide to Shipper the gathering and transportation services contemplated by this Agreement. For purposes of the Tariff, this Agreement shall be deemed: (i) a term contracted Transportation Service Agreement (“TSA”) with Monarch whereby Shipper has agreed to terms and conditions associated with supporting the initial construction of a pipeline of Monarch, and shall enjoy all of the rights and benefits provided to such agreements in the Tariff and pursuant to FERC rules and regulations.  The Committed Rate set forth in this TSA is not required to be cost-based to meet a statutory “just and reasonable” standard as long as the rate is set in a manner that is not unduly preferential or discriminatory

SECTION XVI

FORCE MAJEURE

A.The term “Force Majeure,” shall mean any cause or event not reasonably within the control of the Party whose performance is sought to be excused thereby, including (1) acts of God, strikes, lockouts, or other industrial disputes or disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, tornadoes, hurricanes, storms, severe winter weather, and warnings for any of the foregoing which may necessitate the precautionary shut-down of wells, plants, pipelines, the Pipeline, truck unloading facilities; (2) failure of any parties downstream of the Delivery Point(s) (except for downstream parties that are Affiliates of Monarch) to timely install or provide interconnection or receipt facilities, or other related facilities; (3) floods, washouts, arrests and restraints of governments and people, civil disturbances, explosions, sabotage, breakage or accidents to equipment, machinery, plants, truck unloading facilities, other related facilities, or lines of pipe; (4) the making of repairs or alterations to lines of pipe, the Pipeline, truck unloading facilities, plants or equipment; (5) freezing of wells or lines of pipe; (6) electric power shortages; (7) necessity for compliance with any court order, or any law, statute, ordinance, regulation or order promulgated by a Governmental Authority having or asserting jurisdiction, unless such necessity arises as a result of Monarch’s or its Affiliates’ failure to comply with any Applicable Law (provided that Monarch shall be permitted to resist in good faith the application to it of any such law by all reasonable legal means) ; (8) inability to obtain necessary permits, rights of way or materials for construction, maintenance or operations provided same were timely and diligently pursued; (9) inclement weather that necessitates extraordinary measures and expense to construct facilities or maintain operations; and (10) any other causes, whether of the kind enumerated herein or otherwise, not reasonably within the control of the Party claiming suspension, including any such cause or event occurring with respect to the facilities, services, equipment, goods, supplies or other items necessary to the performance of such Party’s obligations hereunder. “Force Majeure” also includes any event of Force Majeure occurring with

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respect to the facilities or services of either Party’s Affiliates or service providers providing a service or providing any equipment, goods, supplies or other items necessary to the performance of such Party’s obligations hereunder.

B.If Party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this Agreement (other than the obligation to make payments of monies due hereunder), then Party shall give prompt written Notice of the Force Majeure stating facts supporting such claim of inability to perform.  Thereupon, Party’s obligation to perform shall be suspended during the period it is unable to perform because of the Force Majeure, but for no longer period, and this Agreement shall otherwise remain unaffected.  Party shall use due diligence to remove the cause of Force Majeure, where commercially practicable, with all reasonable dispatch; provided, however, that this provision shall not require the settlement of strikes, lockouts, or other labor difficulty, when such course is determined inadvisable by Party.

C.During any event(s) of Force Majeure affecting Monarch’s ability to transport Shipper’s Dedication, Shipper shall be released from its obligation hereunder to deliver the Crude Oil to Monarch at the Receipt Point(s) pursuant to Sections VI.a.v and VI.a.vi.

SECTION XVII

MAINTENANCE

A.Monarch shall have the exclusive responsibility, control and management over the operation, maintenance and repair of the Facilities.  Monarch shall perform its obligations under this Agreement in a good and workmanlike manner, in its judgment as a reasonably prudent operator, and in conformity with the practices in the industry and particular circumstances operating in Lipscomb County, Texas and Roger Mills County, Oklahoma.

B.Monarch may interrupt its performance for a reasonable period of time for the purpose of making necessary or desirable inspections, alterations, and repairs (“Maintenance”) and Monarch shall give Shipper reasonable Notice of its intention to suspend its performance, except in cases of emergency where such Notice is impracticable or in cases where the operations of Shipper will not be affected. Monarch shall endeavor to arrange such interruptions so as to inconvenience Shipper as little as possible. For these circumstances, the provisions of Item No. 110(a) of the Rules and Regulations, or its successor, shall apply.

C.During any event(s) of Maintenance affecting Monarch’s ability to transport Shipper’s Dedication for a period in excess of seven (7) Days, such Maintenance shall be deemed an Interruption and Curtailment event and Shipper shall be released from its obligation hereunder to deliver the Crude Oil to Monarch at the Receipt Point(s) pursuant to Sections VI.a.v and VI.a.vi.

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SECTION XVIII

ASSIGNMENT

A.Except as otherwise provided in this Section XVIII, neither Party may assign all or a portion of its rights and obligations under this Agreement without the prior written consent of the non-assigning Party, provided that such consent shall not be unreasonably withheld or delayed.

B.Notwithstanding Section XVIII.A, either Party shall have the right without the prior consent of the other Party to: (i) assign its rights and obligations under this Agreement (in whole or in part) to an Affiliate; (ii) mortgage, pledge, encumber, or otherwise impress a lien, create a security interest or otherwise assign as collateral its rights and interests in and to the Agreement to any lender; (iii) make a transfer pursuant to any security interest arrangement described in (ii) above, including any judicial or non-judicial foreclosure and any assignment from the holder of such security interest to another Person; or (iv) assign the Agreement in connection with the sale of all or substantially all of its assets, or in connection with a merger, consolidation, or other reorganization.  If a Party assigns its rights and obligations under this Agreement (in whole or in part) pursuant to clauses (i) or (iv) above, such Party shall require the assignee to assume such Party’s obligations hereunder and become a signatory to this Agreement, and such assignee shall be bound by the terms herein.

C.If Monarch desires to sell the Pipeline to an unaffiliated third party prior to its completion, including through a change of control (excepting a public offering of equity or other ownership by Monarch), Monarch will require the buyer of the Pipeline to assume Monarch’s obligations under this Agreement, along with any future modification to the Facilities contemplated in this Agreement.

SECTION XIX

LIMITATION ON LIABILITY AND INDEMNITY

A.Shipper’s Liability and Indemnification.

i.Shipper shall be in control and possession of the Crude Oil until delivered to Monarch at the Receipt Point(s) and following delivery of the Crude Oil by Monarch at the Delivery Point(s).  Monarch shall be in control and possession of the Crude Oil following delivery by Shipper at the Receipt Point(s) and prior to re-delivery to Shipper at the Delivery Point(s).

ii.Shipper agrees to indemnify, defend, and hold harmless Monarch from any and all Losses arising from or out of personal injury or property damage attributable to Shipper’s Crude Oil when Shipper shall be deemed to be in control and possession of Shipper’s Crude Oil as provided in Section XIX.A.i.  Monarch agrees to indemnify, defend, and hold harmless Shipper from all Losses arising from or out of personal injury or property damage attributable to Shipper’s Crude Oil when Monarch shall be deemed to be in control and possession of Shipper’s Crude Oil as provided in Section XIX.A.i.  THE INDEMNITIES SET FORTH IN THIS SECTION XIX.A.ii ARE TO BE CONSTRUED WITHOUT REGARD TO

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THE CAUSES THEREOF, INCLUDING THE NEGLIGENCE OF ANY INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE, OR THE STRICT LIABILITY OF ANY INDEMNIFIED PARTY OR OTHER PERSON.  Each Party agrees that its voluntary and mutual indemnity agreement will be supported by insurance and that such insurance shall not be deemed to be a cap on liability.

B.Disclaimer of Damages.  A PARTY’S LIABILITY HEREUNDER SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY.  SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED.  NEITHER PARTY SHALL BE LIABLE HEREUNDER TO THE OTHER PARTY OR ITS AFFILIATES FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS (OTHER THAN DIRECT, ACTUAL LOST PROFITS), OR OTHER BUSINESS INTERRUPTION OR SIMILAR DAMAGES, BY STATUTE, IN TORT, OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE.  IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE STRICT LIABILITY OR NEGLIGENCE OF ANY PARTY, WHETHER SUCH STRICT LIABILITY OR NEGLIGENCE BE SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE.

SECTION XX

REPRESENTATIONS AND WARRANTIES

A.Representations and Warranties of Shipper.  Shipper represents and warrants that:

i.It is duly organized and validly existing under the laws of the jurisdiction of its organization or incorporation and has all requisite legal power and authority to execute, deliver and perform its obligations and duties in this Agreement;

ii.This Agreement constitutes the valid, legal and binding obligation of Shipper, enforceable in accordance with the terms contained in this Agreement;

iii.The execution, delivery and performance by Shipper of this Agreement does not and will not conflict with or result in any breach or contravention of, or the creation of any lien or other encumbrance under, any contractual obligation to which Shipper is a party or to which the Crude Oil is subject.

iv.There are no actions, suits or proceedings pending before any court or administrative body that are likely to materially adversely affect the ability of Shipper to meet and carry out its obligations under this Agreement.

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v.The Crude Oil that Shipper gathers and transports subject to its Committed Volume is produced from Shipper’s Dedication.

vi.That Shipper controls or has the right to market the interest in the Crude Oil, and has the right to ship and/or market said Crude Oil, free from all liens and adverse claims of title and Monarch has the right to suspend its receipt of any of Shipper’s Crude Oil subject to any title claims until they are resolved to Monarch’s satisfaction.

vii.Shipper will release, indemnify and defend Monarch from and against any and all damages, claims, actions, expenses, penalties and liabilities, including attorney’s fees, arising from any breach of the foregoing representations and warranties.

viii.The representations and warranties in this Agreement shall survive the execution of this Agreement and shall remain in full force and effect for the entire Term.

B.Representations and Warranties of Monarch.  Monarch represents and warrants that:

i.It is duly organized and validly existing under the laws of the jurisdiction of its organization or incorporation and has all requisite legal power and authority to execute, deliver and perform its obligations and duties in this Agreement;

ii.This Agreement constitutes the valid, legal and binding obligation of Monarch, enforceable in accordance with the terms contained in this Agreement;

iii.The execution, delivery and performance by Monarch of this Agreement does not and will not conflict with or result in any breach or contravention of, or the creation of any lien or other encumbrance under, any contractual obligation to which Monarch is a party or to which the Crude Oil is subject.

iv.There are no actions, suits or proceedings pending before any court or administrative body that are likely to materially adversely affect the ability of Monarch to meet and carry out its obligations under this Agreement.

v.Monarch will release, indemnify and defend Shipper from and against any and all damages, claims, actions, expenses, penalties and liabilities, including attorney’s fees, arising from any breach of the foregoing representations and warranties.

vi.The representations and warranties in this Agreement shall survive the execution of this Agreement and shall remain in full force and effect for the entire Term of this Agreement.

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SECTION XXI

FUTURE EXPANSIONS OF THE PIPELINE

Subject to Monarch’s rights and obligations pursuant to the Interstate Commerce Act and other Applicable Law, Monarch shall have the right, at its sole discretion, to expand the capacity of all or parts of the Pipeline at any time or from time to time; provided, however, that no such expansion shall degrade the Services provided hereunder.  Monarch reserves the right to hold an additional open season and to enter into transportation services agreements for the capacity added during any expansion at terms to be determined by Monarch. Any such expansion shall not affect the obligations established in this Agreement.

SECTION XXII

MISCELLANEOUS

A.Confidentiality.  A Party that receives information (“Information Receiving Party”) shall maintain in the strictest confident, for the benefit of the other Party (“Disclosing Party”), all information pertaining to the financial terms of or payments under this Agreement, the Disclosing Party’s methods of operation, methods of the Facility, and the like, whether disclosed by the Disclosing Party or discovered by the Information Receiving Party, unless such information either (i) is in the public domain through no act or omission of the Information Receiving Party or its employees or agents, (ii) was already known to the Information Receiving Party at the time of disclosure and which the Information Receiving Party is free to use or disclose without breach of any obligation to any person or entity, (iii) is required to be disclosed by Applicable Law, or (iv) is disclosed to regulators in furtherance of obtaining regulatory approval, provided that such disclosure is provided under seal. Neither Party shall use such information for its own benefit, publish or otherwise disclose it to others, or permit its use by others for their benefit or to the detriment of the other Party. Notwithstanding the foregoing, the Information Receiving Party may disclose such information to any auditor or to the Information Receiving Party’s lenders, attorneys, accountants and other personal advisors; any prospective purchaser of the Facility; or pursuant to lawful process, subpoena or court order; provided the Information Receiving Party, in making such disclosure, advises the party receiving the information of the confidentiality of the information and obtains the agreement of said party not to disclose the information.

B.Notice.  Except for nominations submitted pursuant to Section IX.A, all notices and other communications required or permitted under this Agreement (each, a “Notice”) shall be in writing and addressed as set forth herein. Any Notice shall be deemed to have been duly made and the receiving Party charged with receipt of such Notice (i) if personally delivered, when received, (ii) if sent by electronic mail, telecopy or facsimile transmission, on the Business Day on or which such electronic mail, telecopy, or

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facsimile is successfully transmitted and received, or if such electronic mail, telecopy, or facsimile transmission was successfully transmitted and received after 5:00 pm local time of the receiving party, then the next Business Day, (iii) if mailed by certified mail, return receipt requested, the fifth (5th) Business Day after mailing, or (iv) if sent by overnight courier, on the day such Notice is successfully delivered to the receiving party. All Notices shall be addressed as follows

	Notices and Correspondences:
Shipper:	Jones Energy, LLC
	Attn: Denise Herbert
	807 Las Cimas Parkway, Suite 350
	Austin, Texas 78746
	Telephone: (512) 493-4841
	Facsimile:
	E-mail: dherbert@jonesenergy.com
Monarch:	Monarch Oil Pipeline, LLC
	Attn: Judson Williams
	5613 DTC Parkway, Suite 310
	Greenwood Village, Colorado 80111
	Telephone: (720) 381-4581
	Facsimile: (720) 235-0228
	E-mail: jwilliams@mngllc.com

Any Party may, by written Notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made in accordance with this Section XXII.B.

C.Memorandum of Agreement.  The Parties agree to promptly execute and record a Memorandum of Crude Oil Gathering and Transportation Agreement substantially in the form of Exhibit D following the execution of this Agreement.

D.Governing Law: Venue and Jurisdiction.  This Agreement shall be construed, enforced, and interpreted according to the laws of the State of Texas, without regard to the conflicts of law rules thereof.  Any action brought in respect of this Agreement must be brought in the state or federal courts sitting in Harris County, Texas.

E.Waiver.  No waiver of any breach of this Agreement by a Party shall be held to be a waiver of any other or subsequent breach.

F.Amendments.  This Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the Party claiming the benefit of such amendment or waiver.

27

G.Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute but one and the same instrument.  Facsimile signatures shall be considered binding.

H.Entire Agreement.  This Agreement constitutes the entire understanding among the Parties with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements and understandings relating to such subject matter.  The terms and conditions of this Agreement shall supersede any previous oral or written agreements between the Parties.

I.Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of the Parties hereto and their respective permitted successors and assigns.

J.Severability.  If any part of this Agreement is held to be void or unenforceable by any court or under any law, that part shall be deemed stricken and all remaining provisions shall continue to be valid and binding upon the Parties.

K.No Third-Party Beneficiaries.  This Agreement is intended to benefit only the Parties hereto and their respective permitted successors and assigns.

L.Contract Revision.  Notwithstanding anything in this Agreement to the contrary, whether express or implied, the Parties do not intend for this Agreement or any provision of this Agreement to be subject to revision by any Governmental Authority, including FERC.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the Effective Date.

JONES ENERGY, LLC
SHIPPER
By:	/s/ Jonny Jones
Name:	Jonny Jones
Title:	Chief Executive Officer
MONARCH OIL PIPELINE, LLC
PIPELINE
By:	/s/ Terry Klare
Name:	Terry Klare
Title:	President and COO

28

EXHIBIT A

ATTACHMENT TO THE

AMENDED AND RESTATED

TRANSPORTATION AND GATHERING SERVICES AGREEMENT

Between

MONARCH OIL PIPELINE, LLC

and

JONES ENERGY, LLC

as of the 23rd day of October, 2015

COMMITTED SHIPPER PROGRAM

1

EX-21.1

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Exhibit 21.1

Subsidiaries

Entity	State of Formation
Jones Energy Holdings, LLC	Delaware
Jones Energy Finance Corp.	Delaware
CCPR Sub LLC	Delaware
Nosley Assets, LLC	Delaware
Jones Energy, LLC	Texas
JRJ Opco, LLC	Texas

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Exhibit 21.1

EX-23.1

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-197809) and S-8 (333-190471) of Jones Energy, Inc. of our report dated March 9, 2016 relating to the consolidated financial statements, which appears in this Form 10-K.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 9, 2016

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

EX-23.2

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Exhibit 23.2

Consent of Independent Petroleum Engineers and Geologists

        We hereby consent to the references to our firm in this Annual Report on Form 10 K for the year ended December 31, 2015 (including any amendments thereto, the "Annual Report") filed by Jones Energy, Inc. (the "Company"). We hereby further consent to the use and incorporation by reference of information from our reports regarding those quantities estimated by us of reserves and the value of reserves as of December 31, 2013, 2014 and 2015 for Jones Energy Holdings, LLC. In addition, we hereby consent to the inclusion of our summary report dated January 28, 2016 as an exhibit to the Annual Report. We further consent to the incorporation by reference thereof into the Company's Registration Statements on Form S-8 (File No. 333-190471) and Form S-3 (No. 333-197809).

/s/ W. TODD BROOKER
W. Todd Brooker, P.E.
Senior Vice President
Cawley Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693.
Austin, Texas
March 9, 2016

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Exhibit 23.2

Consent of Independent Petroleum Engineers and Geologists

EX-31.1

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Exhibit 31.1

Certification by Chief Executive Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Jonny Jones, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Jones Energy, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

By: /s/ JONNY JONES
Jonny Jones
Chief Executive Officer

Date: March 9, 2016

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Exhibit 31.1

Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

EX-31.2

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Exhibit 31.2

Certification by Chief Financial Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Robert J. Brooks, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Jones Energy, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

By: /s/ ROBERT J. BROOKS
Robert J. Brooks
Chief Financial Officer

Date: March 9, 2016

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Exhibit 31.2

Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

EX-32.1

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Exhibit 32.1

Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the annual report of Jones Energy, Inc. (the "Company") on Form 10-K for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Jonny Jones, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ("Section 906"), that, to my knowledge:

1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By: /s/ JONNY JONES
Jonny Jones
Chief Executive Officer

Date: March 9, 2016

        A signed original of this written statement required by Section 906 has been provided to the Company and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32.1

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

EX-32.2

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Exhibit 32.2

Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the annual report of Jones Energy, Inc. (the "Company") on Form 10-K for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert J. Brooks, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ("Section 906"), that, to my knowledge:

1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By: /s/ ROBERT J. BROOKS
Robert J. Brooks
Chief Financial Officer

Date: March 9, 2016

        A signed original of this written statement required by Section 906 has been provided to the Company and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32.2

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

EX-99.1

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Exhibit 99.1

January 28, 2016

Mr. Eric Niccum
Jones Energy Holdings, LLC
807 Las Cimas Parkway, Suite 350
Austin, Texas 78746

Re:	Evaluation Summary
	Jones Energy Holdings, LLC Interests Total Proved Reserves As of December 31, 2015
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Dear Mr. Niccum:

        As requested, this report was prepared on January 28, 2016 for Jones Energy Holdings, LLC (JEH) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to JEH interests. We evaluated 100% of the Company reserves, which are made up of various oil and gas properties in various states. This evaluation utilized an effective date of December 31, 2015, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:

		Proved Developed Producing		Proved* Developed Non-Producing		Proved Undeveloped		Total Proved		Proved Developed
Net Reserves
Oil	–Mbbl		10,829.3		202.4		14,376.5		25,408.2		11,031.7
Gas	–MMcf		164,303.6		5,347.8		91,944.6		261,596.1		169,651.4
NGL	–Mbbl		19,176.6		493.0		12,979.6		32,649.1		19,669.5
BOE	–Mbbl		57,389.8		1,586.7		42,680.2		101,656.7		58,976.4
Revenue
Oil	–M$		497,151.7		9,328.6		661,590.4		1,168,070.6		506,480.3
Gas	–M$		386,495.2		12,415.8		221,759.3		620,670.3		398,911.1
NGL	–M$		342,395.5		8,753.2		224,527.4		575,675.8		351,148.6
Other	–M$		3,660.2		0.0		5,893.9		9,554.1		3,660.3
Severance Taxes	–M$		73,145.7		1,798.8		52,055.3		126,999.7		74,944.5
Ad Valorem Taxes	–M$		12,637.7		231.3		11,126.0		23,994.9		12,868.9
Operating Expenses	–M$		295,156.0		7,532.5		168,345.9		471,034.6		302,688.6
Other Deductions	–M$		91,413.4		1,739.8		71,224.4		164,377.5		93,153.2
Investments	–M$		32,857.7		4,273.9		445,928.0		483,059.6		37,131.6
Net Operating Income	–M$		705,824.3		14,276.0		349,038.1		1,069,138.3		720,100.2
Discounted @ 10%	–M$		391,100.7		6,367.6		72,394.1		469,862.5		397,468.3

(Present Worth)

*

Proved Developed Non-Producing shown above also includes Proved Developed Shut-In properties.

        Proved Developed ("PD") reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 11,031.7 Mbbl oil, 169,651.4 MMcf gas and 19,669.5 Mbbl NGLs (or 58,976.4 MBOE). Of the Proved Developed reserves, 57,389.8 MBOE were attributed to producing zones in existing wells and 1,586.7 MBOE were attributed to zones in existing wells not producing. Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.

        Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (net operating income) is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its "present worth". The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

        The oil reserves include oil and condensate. Oil volumes and natural gas liquids (NGLs) are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. BOE (barrels of oil equivalent) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels.

Presentation

        The report is divided into a summary section and four reserve category sections. The summary section includes Total Proved ("TP") and Proved Developed ("PD") tabulations. The four reserve category sections include: Proved Developed Producing ("PDP"), Proved Developed Non-Producing ("PDNP"), Proved Developed Shut-In ("PDSI") and Proved Undeveloped ("PUD). Within certain reserve category sections are Tables I, Summary Plots and Tables II. Table I displays composite reserve estimates and economic forecasts for the particular reserve category. The Summary Plot is a composite rate-time history-forecast curve for the properties summarized in the corresponding Table I. Following certain Summary Plots are Table II "oneline" summaries that present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the corresponding Table I. The Table II is sorted by production area and lease name.

        For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter. The data presented in the composite Tables I are explained in page 1 of the Appendix. The methods employed in estimating reserves are described in page 2 of the Appendix.

Hydrocarbon Pricing

        The base SEC oil and gas prices calculated for December 31, 2015 were $50.25/bbl and $2.59/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (Bloomberg) during 2015 and the base gas price is based upon Henry Hub spot prices (Bloomberg) during 2015.

        As provided, oil and gas price differentials were applied and may include adjustments for local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. NGL prices were determined to be approximately 38% of WTI-Cushing oil prices based upon data provided by JEH. The gas price differentials provided were based on the last

2

twelve months average of the following indices: ANR, PEPL, DEMARC, Centerpoint and NGPL or a blended average of these indices. Gas basis differentials are in $/MMBtu units as follows:

Mo-Yr	Panhandle TX/OK (PEPL)			ANR Pipeline Company OK (ANR)			Nat. Gas Pipeline Co. of America Mid-Con. (NGPL)			Centerpoint East (Centerpoint)			No. Nat. Gas Demarcation (DEMARC)
01-2015		–0.25			–0.18			–0.09			–0.11			0.05
Thereafter		0.0	%		0.0	%		0.0	%		0.0	%		0.0	%
Cap		–0.25			–0.18			–0.09			–0.11			0.05

        After these pricing adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $45.972 per barrel for oil, $2.373 per MCF for gas and $17.632 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

        Operating expenses, other deductions and capital expenditures were not escalated. Lease operating expenses for most wells were forecasted on a per well basis with some utilizing an average expense for the area as provided by JEH and audited in detail by Cawley, Gillespie and Associates, Inc. Gas compression, processing and transportation fees were applied to each property as provided and can be found as Other Deductions (column 27) in the attached tables. Properties feeding the Cleveland Pipeline System are charged a supplemental $0.258/MCF and the operating cost for the Cleveland Pipeline cases are incorporated into the individual properties operating cost. Properties feeding the Giant Pipeline System are charged a supplemental $0.148/MCF and the operating cost for the Giant Pipeline case is incorporated into the individual properties operating cost.

        For Texas properties, oil and gas severance tax values were determined by applying normal state tax rates of 4.6% of oil revenue and 7.5% of gas revenue. Ad Valorem taxes were applied at rate of 1.73% of revenue by property as provided. The Cleveland horizontal wells qualify for the "High-Cost Gas Incentive" state severance tax reduction; therefore, gas severance taxes were applied at 2.5% of gas revenue for 10 years after the start of production and then returned to normal rates of 7.5% for the remaining life of each property as scheduled by JEH. Other severance tax reduction scenarios were established for certain properties as scheduled by JEH.

        For Oklahoma properties, a severance tax of 7.095% of revenue was applied to all vertical producing wells. A severance tax reduction as outlined in the Oklahoma horizontal well tax incentive guidelines was applied to existing and future horizontal wells. Reduced severance taxes of 2.095% of revenue were applied to horizontal wells for 36 months if drilled January 1, 2016 or after. No ad valorem taxes were applied for Oklahoma properties. Taxes for other states were applied at standard rates.

Reserves and Drilling Locations

        We evaluated 1018 PDP properties for this report, including the two (2) Pipeline System cases, and 111 PDNP properties with start dates and investments as provided. The Pipeline Systems were modeled by estimating anticipated throughput volumes and applying current economic and contract parameters. Revenue for the pipeline system is shown as Other Revenue (column 16) in the attached tables. Also, 187 PDSI properties were included which require further review by JEH for potential upside or confirmation as P&A candidates.

        This report also includes 412 PUD locations, not all being commercial, in Texas and Oklahoma and one (1) Cleveland Pipeline PUD case. Certain East and West Ellis, Oklahoma PUD gas volumes were used to estimate the incremental gas feeding the Cleveland Pipeline PUD case. The Cleveland

3

reservoir contains 307 PUD locations plus one Cleveland Pipeline Case; the Granite Wash reservoir contains 3 PUD locations; the Upper Granite Wash reservoir contains 24 PUD locations; the Hogshooter reservoir contains 23 PUD locations; and the Woodford reservoir contains 55 PUD locations. In Texas, a maximum of five (5) horizontal proved locations were assigned to each 640-acre section in most cases to be consistent with the Texas field rules and actual development spacing. In Oklahoma, a maximum of five (5) horizontal proved locations were assigned to each 640-acre section based on current field development.

        All PUD drills were assumed to be horizontal wells offsetting production from either vertical or horizontal producers (or both). In the cases where a PUD was offsetting a single vertical producer, reserves were assigned at two times (2X) the vertical well EUR for Cleveland locations, assuming geologic and production control were evident. In the cases where a horizontal PUD Granite Wash location was offsetting a single vertical producer, sufficient nearby Granite Wash vertical and horizontal production had to be established in the region as well as geologic and production control. In all cases, the PUD type curves were either upgraded or downgraded based on offsetting production.

        Capital costs for future drills and workovers were scheduled as provided by JEH. Capital costs were reviewed by CG&A for reasonableness and compared to capital costs provided in previous years. Adjustments were made as necessary after a review with JEH. Drill and complete (D&C) costs varied by region, reservoir and operator. However, net D&C costs averaged $1,386,200 for each of the 307 Cleveland wells, $1,127,200,400 for each of the 3 Granite Wash wells, $287,000 for each of the 24 Upper Granite Wash wells, $309,200 for each of the 24 Hogshooter wells and $535,400 for each of the 55 Woodford wells

SEC Conformance and Regulations

        The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

        Each of the commercial drilling locations proposed as part of the Company's development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

        The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

        Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties

4

targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

        The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

        An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been included as part of this evaluation per the Company

        Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by W. Todd Brooker, Senior Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or Jones Energy Holdings, LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC. TEXAS REGISTERED ENGINEERING FIRM F-693
W. Todd Brooker, P. E. Senior Vice President

5

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Exhibit 99.1

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 29, 2016	Jun. 30, 2015
Entity Registrant Name	Jones Energy, Inc.
Entity Central Index Key	0001573166
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 272.4
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Class A common stock
Entity Common Stock, Shares Outstanding		30,550,907
Class B common stock
Entity Common Stock, Shares Outstanding		31,273,130

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash	$ 21,893	$ 13,566
Restricted cash	330	149
Accounts receivable, net
Oil and gas sales	19,292	51,482
Joint interest owners	11,314	41,761
Other	15,170	12,512
Commodity derivative assets	124,207	121,519
Other current assets	2,298	3,374
Total current assets	194,504	244,363
Oil and gas properties, net, at cost under the successful efforts method	1,635,766	1,638,860
Other property, plant and equipment, net	3,873	4,048
Commodity derivative assets	93,302	87,055
Other assets	17,967	20,352
Deferred tax assets		171
Total assets	1,945,412	1,994,849
Current liabilities
Trade accounts payable	7,467	136,337
Oil and gas sales payable	32,408	70,469
Accrued liabilities	27,341	19,401
Commodity derivative liabilities	11
Asset retirement obligations	679	3,074
Total current liabilities	67,906	229,281
Long-term debt	847,912	860,000
Deferred revenue	11,417	13,377
Commodity derivative liabilities		28
Asset retirement obligations	20,301	10,536
Liability under tax receivable agreement	38,052	803
Deferred tax liabilities	22,972	27,474
Total liabilities	$ 1,008,560	$ 1,141,499
Commitments and contingencies (Note 14)
Stockholders' equity
Treasury stock, at cost; 22,602 shares at December 31, 2015 and December 31, 2014	$ (358)	$ (358)
Additional paid-in-capital	363,723	178,763
Retained earnings (deficit)	36,569	38,950
Stockholders' equity	399,996	217,405
Non-controlling interest	536,856	635,945
Total stockholders' equity	936,852	853,350
Total liabilities and stockholders' equity	1,945,412	1,994,849
Class A common stock
Stockholders' equity
Common stock	31	13
Class B common stock
Stockholders' equity
Common stock	$ 31	$ 37

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Treasury stock
Treasury stock, shares	22,602	22,602
Class A common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	30,573,509	12,672,260
Common Stock, shares outstanding	30,550,907	12,649,658
Class B common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	31,273,130	36,719,499
Common Stock, shares outstanding	31,273,130	36,719,499

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Oil and gas sales	$ 194,555	$ 378,401	$ 258,063
Other revenues	2,844	2,196	1,106
Total operating revenues	197,399	380,597	259,169
Operating costs and expenses
Lease operating	41,027	37,760	25,129
Production taxes	12,130	22,556	15,517
Exploration	6,551	3,453	16,125
Depletion, depreciation and amortization	205,498	181,669	114,136
Accretion of ARO liability	1,087	770	608
General and administrative	33,388	25,763	31,902
Other operating	4,188
Total operating expenses	303,869	271,971	203,417
Operating income (loss)	(106,470)	108,626	55,752
Other income (expense)
Interest expense	(61,289)	(38,805)	(27,409)
Net gain (loss) on commodity derivatives	158,753	189,641	(2,566)
Other income (expense)	(2,852)	(7,624)	(3,443)
Other income (expense), net	94,612	143,212	(33,418)
Income (loss) before income tax	(11,858)	251,838	22,334
Income tax provision (benefit)
Current	113	53	85
Deferred	(2,894)	26,165	(156)
Total income tax provision (benefit)	(2,781)	26,218	(71)
Net income (loss)	(9,077)	225,620	22,405
Net income (loss) attributable to non-controlling interests	(6,696)	184,484	24,591
Net income (loss) attributable to controlling interests	$ (2,381)	$ 41,136	$ (2,186)
Earnings (Loss) per share:
Basic (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)
Diluted (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)
Weighted average shares outstanding:
Basic	26,816	12,526	12,500
Diluted	26,816	12,535	12,500

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Statement of Changes in Stockholders' / Members' Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock Class A common stock	Common Stock Class B common stock	Treasury Stock Class A common stock	Members' Equity	Additional Paid-in-Capital	Retained (Deficit) Earnings	Non-controlling Interest	Total
Balance at Dec. 31, 2012				$ 428,400				$ 428,400
Increase (Decrease) Stockholders' Equity
Sale of common stock	$ 13	$ 37			$ 172,431			172,481
Sale of common stock (in shares)	12,500	36,836
Reclassification of members' contributions				(464,037)			$ 464,037
Stock-compensation expense				10,100	738			10,838
Distribution to members				(10,000)				(10,000)
Net income (loss)				$ 35,537		$ (2,186)	(10,946)	22,405
Balance at Dec. 31, 2013	$ 13	$ 37			173,169	(2,186)	453,091	624,124
Balance (in shares) at Dec. 31, 2013	12,500	36,836
Increase (Decrease) Stockholders' Equity
Treasury Stock			$ (358)					(358)
Treasury Stock (in shares)	(23)		23
Exchange of Class B Shares for Class A Shares					1,554		(1,630)	(76)
Exchange of Class B shares for Class A shares (in shares)	117	(117)
Stock-compensation expense					4,040			4,040
Vested restricted shares (in shares)	28
Net income (loss)						41,136	184,484	225,620
Balance at Dec. 31, 2014	$ 13	$ 37	$ (358)		178,763	38,950	635,945	853,350
Balance (in shares) at Dec. 31, 2014	12,622	36,719	23
Increase (Decrease) Stockholders' Equity
Sale of common stock	$ 12				123,189			123,201
Sale of common stock (in shares)	12,263
Exchange of Class B Shares for Class A Shares	$ 6	$ (6)			54,209		(92,393)	(38,184)
Exchange of Class B shares for Class A shares (in shares)	5,446	(5,446)
Stock-compensation expense					7,562			7,562
Stock-compensation expense (in shares)	67
Vested restricted shares (in shares)	153
Net income (loss)						(2,381)	(6,696)	(9,077)
Balance at Dec. 31, 2015	$ 31	$ 31	$ (358)		$ 363,723	$ 36,569	$ 536,856	$ 936,852
Balance (in shares) at Dec. 31, 2015	30,551	31,273	23

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income (loss)	$ (9,077)	$ 225,620	$ 22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization	205,498	181,669	114,136
Exploration expense	5,250	2,952	14,415
Accretion of ARO liability	1,087	770	608
Amortization of debt issuance costs	6,043	6,878	2,677
Stock compensation expense	7,562	4,040	10,838
Other non-cash compensation expense	455	758	2,719
Amortization of deferred revenue	(1,960)	(1,154)	(469)
(Gain) loss on commodity derivatives	(158,753)	(189,641)	2,566
(Gain) loss on sales of assets	3	(297)	78
Deferred income tax provision	(2,892)	26,165	(156)
Other - net	(961)	376	79
Changes in assets and liabilities
Accounts receivable	64,510	(2,453)	(56,804)
Other assets	(251)	(565)	163
Accrued interest expense	7,050	7,823	1,891
Accounts payable and accrued liabilities	(54,534)	2,482	33,427
Net cash provided by operations	69,030	265,423	148,573
Cash flows from investing activities
Additions to oil and gas properties	(311,305)	(474,619)	(197,618)
Acquisition of properties			(178,173)
Net adjustments to purchase price of properties acquired		15,709
Proceeds from sales of assets	41	448	1,607
Acquisition of other property, plant and equipment	(1,101)	(1,683)	(1,634)
Current period settlements of matured derivative contracts	144,145	(3,654)	7,586
Change in restricted cash	(181)	(104)	(45)
Net cash used in investing	(168,401)	(463,903)	(368,277)
Cash flows from financing activities
Proceeds from issuance of long-term debt	85,000	170,000	220,000
Repayment under long-term debt	(335,000)	(468,000)	(172,000)
Proceeds from senior notes	236,475	500,000
Payment of debt issuance costs	(1,556)	(13,416)	(683)
Proceeds from sale of common stock	122,779		172,481
Purchase of treasury stock		(358)
Net cash provided by financing	107,698	188,226	219,798
Net increase (decrease) in cash	8,327	(10,254)	94
Cash
Beginning of period	13,566	23,820	23,726
End of period	21,893	13,566	23,820
Supplemental disclosure of cash flow information
Cash paid for interest	52,796	29,560	25,414
Cash paid for income taxes	(155)	155
Change in accrued additions to oil and gas properties	(111,210)	49,025	41,945
Current additions to ARO	$ 6,349	$ 1,995	$ 1,516

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Organization and Description of Business

12 Months Ended

Dec. 31, 2015

Organization and Description of Business

Organization and Description of Business

1. Organization and Description of Business

Organization

        Jones Energy, Inc. (the "Company") was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC ("JEH"). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH's business and consolidates the financial results of JEH and its subsidiaries.

        JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital (collectively, the "Pre-IPO owners"). JEH acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties.

        The Company's certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company's initial public offering ("IPO") and can be exchanged (together with a corresponding number of units representing membership interests in JEH ("JEH Units")) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company's stockholders generally. As a result of the IPO and as of February 29, 2016, the Pre-IPO owners had 74.7% and 50.6%, respectively, of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest. Prior to the IPO, JEH owned the controlling interest in the Company; hence all of the net income earned prior to the IPO date is reflected in the net income attributable to non-controlling interests on the Consolidated Statement of Operations for the year ended December 31, 2013.

Description of Business

        The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States. The Company's assets are located within the Anadarko and Arkoma basins of Texas and Oklahoma, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

        During the first quarter of 2015, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the over accrual for production taxes which would have been material to the first quarter of 2015 and could be material to projected 2015 annual results if recorded as an out of period adjustment in such period. Therefore we have revised our Balance Sheet and Consolidated Statement of Operations for the year and quarter ended December 31, 2014, as noted in the table below. This revision had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows for the twelve months ended December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

        In addition, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the exchange of Class B shares for Class A shares. Therefore we revised our Consolidated Balance Sheet and Statement of Changes in Stockholders' Equity for the year ended December 31, 2014 as noted in the table below. This revision had no impact on Class A or Class B shares outstanding at December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

Consolidated Balance Sheet:

	December 31, 2014								December 31, 2014
				Production tax		Exchange of Class B shares
(in thousands of dollars)	As Reported								As Revised
Accounts Receivable, Oil and gas sales	$	49,861		$	1,621		—		$	51,482
Deferred tax liabilities	$	27,330	(1)	$	144		—		$	27,474
Additional paid in capital	$	177,133			—	$	1,630		$	178,763
Retained earnings	$	38,682		$	268		—		$	38,950
Non-controlling interest	$	636,366		$	1,209	$	(1,630	)	$	635,945

(1)Certain prior period amounts have been reclassified to conform to the current presentation.

Consolidated Statements of Operations—for the twelve months ended:

	December 31, 2014						December 31, 2014
				Production tax
(in thousands except per share data)	As Reported						As Revised
Production and ad valorem taxes	$	24,177	(1)	$	(1,621	)	$	22,556
Income tax provision (benefit)	$	26,074		$	144		$	26,218
Net income (loss)	$	224,143		$	1,477		$	225,620
Net income (loss) attributable to non-controlling interests	$	183,275		$	1,209		$	184,484
Net income (loss) attributable to controlling interests	$	40,868		$	268		$	41,136
Earnings (Loss) per share:
Basic	$	3.26		$	0.02		$	3.28
Diluted	$	3.26		$	0.02		$	3.28

(1)Certain prior period amounts have been reclassified to conform to the current presentation.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Significant Accounting Policies

Significant Accounting Policies

2. Significant Accounting Policies

Basis of Presentation

        The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for December 31, 2015 and 2014 and the results of the operations and the cash flows for each of the three years in the period ended December 31, 2014 include the Company and all of its subsidiaries.

        Certain prior period amounts have been reclassified to conform to the current presentation.

Segment Information

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

Use of Estimates

        In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

        Significant assumptions are required in the valuation of proved and unproved oil and natural gas reserves, which affect the Company's estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in the Company's estimates of the net gain or loss on commodity derivative assets and liabilities, fair value associated with business combinations, and asset retirement obligations ("ARO").

Cash

        Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions it does business with, and believes the Company's risk is not significant.

Accounts Receivable

        Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consists at December 31, 2015 and at December 31, 2014 of derivative positions not settled as of the balance sheet date and severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management's best estimate of the amounts that may not be collected. As of December 31, 2015 and 2014, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

        Substantially all of the Company's accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company's overall credit risk in that these entities may be affected similarly by changes in economic and other conditions, including declines in commodity prices. As of December 31, 2015, 68% of Accounts receivable—Oil and gas sales are due from four purchasers and 80% of Accounts receivable—Joint interest owners are due from five working interest owners. As of December 31, 2014, 70% of Accounts receivable—Oil and gas sales were due from five purchasers and 67% of Accounts receivable—Joint interest owners were due from five working interest owners. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales were due from eight purchasers and 77% of Accounts receivable—Joint interest owners were due from five working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company's financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

        The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2015, the largest purchasers were Valero Energy Corp. ("Valero"), ETC Field Services LLC, Plains Marketing LP ("Plains Marketing"), NGL Energy Partners LP, and Unimark LLC, which accounted for approximately 18%, 17%, 16%, 15% and 7% of consolidated oil and gas sales, respectively. During the year ended December 31, 2014, the largest purchasers were Valero Energy Corp. ("Valero"), NGL Energy Partners LP, PVR Midstream LLC ("PVR Midstream"), Plains Marketing LP ("Plains Marketing"), and Monarch Natural Gas LLC which accounted for approximately 22%, 12%, 12%, 10% and 10% of consolidated oil and gas sales, respectively. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria Energy Group Ltd. ("Mercuria"), Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively.

        Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company's purchasers are credit worthy.

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there can be an imbalance between the supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to work interruptions or stoppages, the Company could be materially and adversely affected. Management believes that there are adequate alternative providers of drilling and completion services although it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

Oil and Gas Properties

        The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

        Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

        The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use.

        On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

        Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over the life of proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

        The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk- adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

        The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company's unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company's current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration and development activity by other companies on adjacent blocks.

        On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property, Plant and Equipment

        Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years.

Oil and Gas Sales Payable

        Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

Commodity Derivatives

        The Company records its commodity derivative instruments on the Consolidated Balance Sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the years ended December 31, 2015, 2014 and 2013, the Company elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

        Although the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company's exposure to fluctuations in commodity prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) on the Consolidated Statement of Operations. See Note 7, "Fair Value Measurement," for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

        The Company's asset retirement obligations ("ARO") consist of future plugging and abandonment expenses on oil and natural gas properties. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long- lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments.

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are valued at the estimated sales price and recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the "sales method" of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. Any such imbalances were not significant as of December 31, 2015.

Income Taxes

        Following its IPO on July 29, 2013, the Company began recording a federal and state income tax liability associated with its status as a corporation. No provision for federal income taxes was recorded prior to the IPO because the taxable income or loss was includable in the income tax returns of the individual partners and members. The Company is also subject to state income taxes. The State of Texas includes in its tax system a franchise tax applicable to the Company and an accrual for franchise taxes is included in the financial statements when appropriate.

        Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

        The Company records a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by the Company and may be challenged by the taxation authorities. The Company follows a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. The Company's policy is to include any interest and penalties recorded on uncertain tax positions as a component of income tax expense. The Company's unrecognized tax benefits or related interest and penalties are immaterial.

Comprehensive Income

        The Company has no elements of comprehensive income other than net income.

Recent Accounting Pronouncements

        In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers," which creates a new topic in the ASC, topic 606, "Revenue from Contracts with Customers." This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14 which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. We are currently evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements.

        In January 2015, the FASB issued ASU No. 2015- 01, Income Statement—Extraordinary and Unusual Items. This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30) ("Update 2015-15"), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. The guidance is effective for financial statements issued for annual periods beginning after 15 December 2016, and interim periods within those annual periods. Early adoption is permitted. The guidance may be adopted on either a prospective or retrospective basis. The Company has chosen to early adopt ASU No. 2015-17 for the period ended December 31, 2015. Changes to the balance sheet have been applied on a retrospective basis. Adoption did not have a material impact on the financial position, cash flows or results of operations.

        In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

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Properties, Plant and Equipment

12 Months Ended

Dec. 31, 2015

Properties, Plant and Equipment

Properties, Plant and Equipment

3. Properties, Plant and Equipment

Oil and Gas Properties

        The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas properties consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	2015			2014
Mineral interests in properties
Unproved	$	75,308		$	94,526
Proved		1,031,669			1,001,194
Wells and equipment and related facilities		1,289,323			1,094,202
		2,396,300			2,189,922
Less: Accumulated depletion and impairment		(760,534	)		(551,062	)
Net oil and gas properties	$	1,635,766		$	1,638,860

        As of December 31, 2015 and 2014, we had no material capitalized costs associated with exploratory wells.

        No interest costs were capitalized in 2015. The Company capitalized less than $0.1 million in interest costs during 2014. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        Depletion of oil and gas properties amounted to $204.2 million, $180.6 million, and $113.3 million for the years ended December 31, 2015, 2014, and 2013, respectively.

        No impairments of proved or unproved properties were recorded in 2015, 2014, or 2013. Certain prior period amounts have been reclassified to conform to the current presentation, include the reclassification of Impairment of oil and gas properties to Exploration in the Consolidated Statement of Operations for the twelve months ended December 31, 2013 relating to lease abandonment charges of $14.4 million for certain leases that the Company did not plan to develop.

Other Property, Plant and Equipment

        Other property, plant and equipment consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	2015			2014
Leasehold improvements	$	1,260		$	1,218
Furniture, fixtures, computers and software		4,090			3,727
Vehicles		1,537			988
Aircraft		910			910
Other		247			219
		8,044			7,062
Less: Accumulated depreciation and amortization		(4,171	)		(3,014	)
Net other property, plant and equipment	$	3,873		$	4,048

        Depreciation and amortization of other property, plant and equipment amounted to $1.3 million, $1.1 million, and $0.8 million during the years ended December 31, 2015, 2014 and 2013, respectively.

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Acquisition of Properties

12 Months Ended

Dec. 31, 2015

Acquisition of Properties

Acquisition of Properties

4. Acquisition of Properties

        No business combinations occurred during the twelve months ended December 31, 2015 and 2014.

        On December 18, 2013, JEH closed on the purchase of certain oil and natural gas properties located in Texas and western Oklahoma from Sabine Mid-Continent, LLC, for a purchase price of $193.5 million (referred to herein as the "Sabine acquisition" or "Sabine"), subject to customary closing adjustments. The acquired assets included both producing properties and undeveloped acreage. The purchase was financed with borrowings under the Revolver. In the second quarter of 2014, the Company made a final determination with the sellers as to the purchase price resulting in a final purchase price of $179.2 million. The amount of the total purchase price allocated to undeveloped oil and gas properties was reduced by these adjustments. The adjustments were retroactively applied to our December 31, 2013 Consolidated Balance Sheet as a reduction to oil and gas properties and an increase in receivables. The adjusted purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	32,964
Proved		147,024
Asset retirement obligations		(824	)
Total purchase price	$	179,164

        The unaudited pro forma results presented below have been prepared to include the effect of the Sabine acquisition on our results of operations for the year ended December 31, 2013. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on January 1, 2013 or to project our results of operations for any future date or period.

			Year Ended December 31, 2013
	Post Acquisition(1)
(in thousands of dollars)			Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses		291		229,648
Operating income		1,074		79,125
Net income		1,074		45,778

(1)Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

        The acquisition qualified as a business combination. The valuation to determine the fair values were principally based on the discounted cash flows of the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the market at the time of acquisition.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Long-Term Debt

Long-Term Debt

5. Long-Term Debt

        Long-term debt consisted of the following at December 31, 2015 and 2014:

(in thousands of dollars)	December 31, 2015			December 31, 2014
Revolver	$	110,000		$	360,000
2022 Notes		500,000			500,000
2023 Notes		250,000			—
Total principal amount		860,000			860,000
Less: unamortized discount		(12,088	)		—
Total carrying amount	$	847,912		$	860,000

Senior Unsecured Notes

        On April 1, 2014, JEH and Jones Energy Finance Corp., JEH's wholly-owned subsidiary formed for the sole purpose of co-issuing certain of JEH's debt (together the "Issuers"), sold $500.0 million in aggregate principal amount of the Issuers' 6.75% senior notes due 2022 (the "2022 Notes"). The Company used the net proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding borrowings under the Revolver ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014.

        On February 5, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 2022 Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2022 Notes do not apply to the new 2022 Notes. On February 20, 2015, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $500 million outstanding principal amount of 2022 Notes for an equal amount of new 2022 Notes. The exchange offer expired on March 23, 2015. Tenders of $500 million aggregate principal amount, or 100%, of the 2022 Notes were received.

        On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the "2023 Notes") in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015.

        On November 18, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 2023 Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2023 Notes do not apply to the new 2023 Notes. See Note 15, "Subsequent Events," in the Notes to Consolidated Financial Statements for further discussion.

        The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

        The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.

        The indentures governing the 2022 Notes and 2023 Notes are substantially similar and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company's restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company's assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the Notes are rated investment grade.

Other Long-Term Debt

        The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the "Revolver") and the Second Lien Term Loan (the "Term Loan"), each of which have been or were amended periodically. On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, increase the borrowing base under the Revolver from $550.0 million to $625.0 million until the next redetermination thereof, and extend the maturity date of the Revolver to November 6, 2019. The Company's oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015. Effective October 8, 2015, the borrowing base was reduced to $510 million during the semi-annual borrowing base re-determination.

        The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be redetermined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such redetermination based primarily on reserve reports using lender commodity price expectations at such time. In light of current commodity prices, it is our expectation that the borrowing base will be reduced during the upcoming redetermination. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

        Interest on the Revolver is calculated, at the Company's option, at either (a) the London Interbank Offered ("LIBO") rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one-month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the year ended December 31, 2015, the average interest rate under the Revolver was 2.39% on an average outstanding balance of $144.9 million. For the year ended December 31, 2014, the average interest rate under the Revolver was 2.51% on an average outstanding balance of $333.8 million.

        Total interest and commitment fees under the Revolver were $5.1 million, $9.5 million, and $12.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Total interest and commitment fees under the Term Loan were $3.6 million and $14.7 million for the years ended December 31, 2014 and 2013, respectively.

        Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

•           a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and

•           a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

        As of December 31, 2015, our total leverage ratio is approximately 3.2 and our current ratio is approximately 6.9, as calculated based on the requirements in our covenants. We believe that we are in compliance with all terms of our Revolver and expect to maintain compliance during 2016. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2016 and beyond. In the event it were to became necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as hedge restructuring. While it is our expectation that we will continue to be in compliance with our covenants, no assurance can be given that this will be the case. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

6. Derivative Instruments and Hedging Activities

        The Company had various commodity derivatives in place that could affect its future operations as of December 31, 2015 and 2014, as follows:

Hedging Positions

	December 31, 2015
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.16
	Barrels per month		54,000			194,000			97,119		June 2019
Natural gas swaps	Exercise price	$	3.22		$	6.45		$	4.25
	mmbtu per month		700,000			1,640,000			1,042,857		June 2019
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.18	)
	mmbtu per month		1,190,000			1,730,000			1,360,833		December 2016
Natural gas liquids swaps	Exercise price	$	8.90		$	95.24		$	32.62
	Barrels per month		2,000			112,000			51,792		December 2017

	December 31, 2014
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	75.05		$	100.95		$	84.20
	Barrels per month		45,000			184,054			113,852		December 2018
Natural gas swaps	Exercise price	$	3.37		$	6.45		$	4.40
	mmbtu per month		710,000			1,772,584			1,175,275		December 2018
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.21	)
	mmbtu per month		320,000			980,000			716,667		March 2016
Natural gas liquids swaps	Exercise price	$	8.09		$	95.24		$	42.46
	Barrels per month		2,000			143,000			50,444		December 2017

        The Company recognized a net gain on derivative instruments of $158.8 million and $189.6 million for the years ended December 31, 2015 and 2014, respectively, and a net loss of $2.6 million for the year ended December 31, 2013.

Offsetting Assets and Liabilities

        As of December 31, 2015, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

        Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

        We adopted the guidance requiring disclosure of both gross and net information about financial instruments eligible for netting in the balance sheet under our derivative agreements. The following table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of December 31, 2015 and December 31, 2014:

(in thousands of dollars)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities		(538	)		527			(11	)		—		(11	)
December 31, 2014
Commodity derivative contracts
Assets	$	208,646		$	(72	)	$	208,574		$	—	$	208,574
Liabilities		(100	)		72			(28	)		—		(28	)

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Fair Value Measurement

12 Months Ended

Dec. 31, 2015

Fair Value Measurement

Fair Value Measurement

7. Fair Value Measurement

Fair Value of Financial Instruments

        The Company determines fair value amounts using available market information and appropriate valuation methodologies. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

        The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

        Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have strong credit quality.

        Liquidity valuation adjustments are necessary when the Company is not able to observe a recent market price for financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional valuation adjustments; therefore, no liquidity reserve is applied.

Valuation Hierarchy

        Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument's categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument's fair value. The three levels are defined as follows:

Level 1	Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date. The Company does not classify any of its financial instruments in Level 1.
Level 2	Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.
Level 3	Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

        The financial instruments carried at fair value as of December 31, 2015 and 2014, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	December 31, 2015
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets		—		93,302		—		93,302
Current liabilities		—		11		—		11
Long-term liabilities		—		—		—		—

	December 31, 2014
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	120,604	$	915	$	121,519
Long-term assets		—		85,162		1,893		87,055
Current liabilities		—		—		—		—
Long-term liabilities		—		—		28		28

        The following table represents quantitative information about Level 3 inputs used in the fair value measurement of the Company's commodity derivative contracts as of December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value (000's)		Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	1,428	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$8.90 - $47.25 per barrel

        Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement. The following table presents the changes in the Level 3 financial instruments for the years ended December 31, 2015 and 2014. Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.

(in thousands of dollars)
Balance at December 31, 2013, net	$	(1,235	)
Purchases		668
Settlements		476
Transfers into Level 3		(265	)
Transfers to Level 2		332
Changes in fair value		2,804
Balance at December 31, 2014, net		2,780
Purchases		648
Settlements		(960	)
Transfers into Level 3		—
Transfers to Level 2		(1,367	)
Changes in fair value		327
Balance at December 31, 2015, net	$	1,428

        Transfers from Level 3 to Level 2 represent the Company's natural gas basis swaps for which observable forward curve pricing information has become readily available. Purchases represent natural gas liquid swaps that the Company entered into that do not have observable forward curve pricing information.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

        The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements:

	December 31, 2015				December 31, 2014
(in thousands of dollars)	Principal Amount		Fair Value		Principal Amount		Fair Value
Debt:
Revolver	$	110,000	$	110,000	$	360,000	$	360,000
2022 Notes		500,000		260,000		500,000		384,375
2023 Notes		250,000		153,283		—		—

        The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

        The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

        The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

        Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include the Company's estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company's AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company's ARO represent a nonrecurring Level 3 measurement.

        The Company reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company's estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligations

Asset Retirement Obligations

8. Asset Retirement Obligations

        A summary of the Company's ARO for the years ended December 31, 2015 and 2014 is as follows:

(in thousands of dollars)	2015			2014
ARO liability at beginning of year	$	13,610		$	10,963
Liabilities incurred(1)		6,349			1,995
Accretion of ARO liability		1,087			770
Liabilities settled due to sale of related properties		(19	)		(109	)
Liabilities settled due to plugging and abandonment		(69	)		(55	)
Change in estimate		22			46
ARO liability at end of year		20,980			13,610
Less: Current portion of ARO at end of year		(679	)		(3,074	)
Total long-term ARO at end of year	$	20,301		$	10,536

(1)Includes $4.7 million to correct immaterial errors originating in 2013 and 2014. In addition to the balance sheet impact noted, Accretion of ARO liability of $0.2 million and Depletion, depreciation, and amortization of $0.6 million were recognized in our statement of operations during the fourth quarter of 2015 as a correcting adjustment. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

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Stock-based Compensation

12 Months Ended

Dec. 31, 2015

Stock-based Compensation

Stock-based Compensation

9. Stock-based Compensation

Management Unit Awards

        Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membership interests in JEH to members of senior management ("management units"). These awards had various vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. In connection with the IPO, both the vested and unvested management units were converted into the right to receive JEH Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new management units have been awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH units that occurred upon forfeiture.

        The following table summarizes information related to the vesting of management units as of December 31, 2015:

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		274,385		$	15.00
Granted		1,909		$	15.00
Forfeited		(1,909	)	$	15.00
Vested		(85,030	)	$	15.00
Unvested at December 31, 2015		189,355		$	15.00

        Stock compensation expense associated with the management units for the years ended December 31, 2015, 2014 and 2013 was $1.3 million, $1.6 million, and $10.7 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. The weighted average grant date fair value of management units was $15.00 per share for the year ended December 31, 2015. Unrecognized expense as of December 31, 2015 for all outstanding management units was $2.8 million and will be recognized over a weighted-average remaining period of 1.2 years.

2013 Omnibus Incentive Plan

        Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the "LTIP"), established in conjunction with the Company's IPO, the Company reserved 3,850,000 shares of Class A common stock for non-employee director, consultant and employee stock-based compensation awards.

        The Company granted (i) performance unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company's non-employee directors under the LTIP during 2014 and 2015.

Restricted Stock Unit Awards

        The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under the LTIP. The fair value of the restricted stock unit awards was based on the value of the Company's Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.

        The following table summarizes information related to the total number of units awarded to officers and employees as of December 31, 2015:

	Restricted Stock Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		324,897		$	17.33
Granted		572,939		$	9.58
Forfeited		(14,995	)	$	12.84
Vested		(125,596	)	$	16.75
Unvested at December 31, 2015		757,245		$	11.65

        Stock compensation expense associated with the employee restricted stock unit awards for the years ended December 31, 2015 and 2014 was $3.1 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. There was no stock compensation expense associated with the employee restricted stock unit awards for the year ended December 31, 2013. The weighted average grant date fair value of restricted stock units was $9.58 per share, and $17.31 per share for the years ended December 31, 2015 and 2014, with no awards made during the year ended December 31, 2013. Unrecognized expense as of December 31, 2015 for all outstanding restricted stock unit awards was $5.9 million and will be recognized over a weighted-average remaining period of 1.1 years.

Performance Unit Awards

        The Company has outstanding performance unit awards granted to certain officers of the Company under the LTIP. Upon the completion of the applicable three-year performance period, each officer may vest in a number of performance units. The percent of awarded performance units in which each officer vests at such time, if any, will range from 0% to 200% based on the Company's total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance unit is exchangeable for one share of the Company's Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance units earned. The fair value of the performance units is expensed on a straight-line basis over the applicable three-year performance period.

        The following table summarizes information related to the total number of units awarded to the officers as of December 31, 2015:

	Performance Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		192,998		$	21.65
Granted		361,422		$	10.27
Forfeited		—			—
Vested		(15,232	)	$	14.59
Unvested at December 31, 2015		539,188		$	14.22

        Stock compensation expense associated with the performance unit awards for the years ended December 31, 2015 and 2014 was $2.6 million and $0.9 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. There was no stock compensation expense associated with the performance unit awards for the year ended December 31, 2013. The weighted average grant date fair value of performance unit awards was $10.27 per share, and $21.65 per share for the years ended December 31, 2015 and 2014, with no awards made during the year ended December 31, 2013. Unrecognized expense as of December 31, 2015 for all outstanding performance unit awards was $4.0 million and will be recognized over a weighted-average remaining period of 1.5 years.

        The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate future stock prices for the Company and the components of the peer group. The simulation uses a risk- neutral framework along with the risk-free rate of return, the volatility of each entity, and the correlations of each entity with the other entities in the peer group. A stock price path has been simulated for the Company and each peer company and is used to determine the payout percentages and the stock price of the Company's common stock as of the vesting date. The ending stock price is multiplied by the payout percentage to determine the projected payout, which is then discounted using the risk-free rate of return to the grant date to determine the grant date fair value for that simulation. When enough simulations are generated, the resulting distribution gives a reasonable estimate of the range of future expected stock prices.

        The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense during the periods presented:

	2015 Performance Unit Awards			2014 Performance Unit Awards
Stock Price(1)	$	10.11		$	17.07
Beginning Average Stock Price(2)	$	11.56		$	14.78
Expected Volatility(3)		55.13	%		46.95	%
Risk-Free Rate of Return(4)		0.79	%		0.61	%

(1)Based on the closing price of Jones Energy, Inc. Class A common stock on April 29, 2015 and May 20, 2014.

(2)Based on the 10 trading days immediately prior to the beginning of the performance period.

(3)For the 2015 award this is based on the average historical volatilities over the most recent 2.67‑year period for the Company and each peer company using daily stock prices through April 29, 2015. The measurement period reflects the 2.67 years remaining in the performance period as of the grant date.

For the 2014 award this is based on the average historical volatilities over the most recent 2.62‑year period for the Company and each peer company using daily stock prices through May 20, 2014. The measurement period reflects the 2.62 years remaining in the performance period as of the grant date.

(4)Based on the yield curve of U.S. Treasury rates as of April 29, 2015 and May 20, 2014.

        Based on these assumptions, the Monte Carlo simulation model resulted in an expected percentage of performance units earned of 101.61% and 126.80% for the 2015 and 2014 awards, respectively.

Restricted Stock Awards

        The Company has outstanding restricted stock awards granted to the Company's non-employee members of the Board of Directors under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company's Class A common stock on the date of grant.

        The following table summarizes information related to the total value of the awards to the Board of Directors as of December 31, 2015:

	Restricted Stock Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		27,430		$	18.77
Granted		67,380		$	7.30
Forfeited		—			—
Vested		(27,430	)	$	18.77
Unvested at December 31, 2015		67,380		$	7.30

        Stock compensation expense associated with the Board of Directors awards for the years ended December 31, 2015, 2014 and 2013 was $0.6 million, $0.4 million, and $0.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. The weighted average grant date fair value of restricted stock awards was $7.30 per share, $18.77 per share, and $15.05 per share for the years ended December 31, 2015, 2014 and 2013. Unrecognized expense as of December 31, 2015 for all outstanding restricted stock awards was $0.2 million and will be recognized over the remaining vesting period of 0.4 years.

        For the years ended December 31, 2015, 2014, and 2013, the Company had an associated tax benefit of $1.1 million, $0.4 million, and $0.1 million, respectively, related to all stock-based compensation, calculated at the federal statutory rate after adjusting for the non-controlling interest.

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Benefit Plans

12 Months Ended

Dec. 31, 2015

Benefit Plans

Benefit Plans

10. Benefit Plans

        The Company established a tax-qualified 401(k) savings plan (the "Plan") for the benefit of employees. The Plan is a defined contribution plan and the Company may match a portion of employee contributions to the Plan. In addition, during 2013, the Company established a non-qualified deferred compensation plan for the benefit of key employees. The non-qualified deferred compensation plan is an unfunded, account-based plan under which key employees of the Company may elect to defer a portion of their base salary and/or bonus. For the year ended December 31, 2015, our total expense relating to these plans was $0.5 million. Our total expense relating to these plans for each of the years ended December 31, 2014 and 2013 was $0.3 million.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes

Income Taxes

11. Income Taxes

        Following its IPO, the Company began recording federal and state income tax liabilities associated with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas franchise tax as the Company's taxable income or loss was includable in the income tax returns of the individual partners and members. The Company will recognize a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.

        The following table summarizes the tax provision for the years ended December 31, 2015, 2014 and 2013:

	Year Ended December 31,
(in thousands of dollars)	2015			2014		2013
Current tax expense:
Federal	$	—		$	53	$	85
State		113			—		—
Total current expense		113			53		85
Deferred tax expense (benefit):
Federal		(1,137	)		22,140		(1,260	)
State		(1,757	)		4,025		1,104
Total deferred expense (benefit)		(2,894	)		26,165		(156	)
Total tax expense (benefit)		(2,781	)	$	26,218	$	(71	)
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819	$	(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399		1,152
Total income tax expense (benefit)		(2,781	)	$	26,218	$	(71	)

        For the pre-IPO period of the year ended December 31, 2013, the reported taxes in the table above relate solely to the Texas franchise tax liability of JEH.

        A reconciliation of the Company's provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate of 35%:

(in thousands of dollars)	2015			2014			2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	(11,858	)	$	251,838		$	22,334
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate	$	(4,150	)	$	88,144		$	7,817
Less: Non-controlling interests		2,911			(65,759	)		(9,009	)
Income tax expense (benefit) attributable to controlling interests		(1,239	)		22,385			(1,192	)
State and local income taxes, net of federal benefit		(1,011	)		626			(49	)
Reduction of TRA liability		(694	)		—			—
Equity compensation, shortfall		338			—			—
Change in enacted rate		(650	)		—			—
Change in valuation allowance		2,333			—			—
Other		(237	)		(192	)		18
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819			(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399			1,152
Total income tax expense (benefit)(1)	$	(2,781	)	$	26,218		$	(71	)

(1)Deferred tax expense of the year ended December 31, 2015 includes the correction of an immaterial error from the year ended December 31, 2014, whereby deferred tax expense was overstated in 2014 and understated in 2015 by $0.9 million. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

        The Company is subject to federal, state, and local income and franchise taxes. As such, deferred income taxes result from temporary differences between the carrying amounts of assets and liabilities of the Company for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates in effect in the years in which those temporary differences are expected to reverse.

        In 2015, Texas enacted legislation that reduced the tax rate from 1.0% to 0.75%. We recorded a tax benefit of $1.7 million as a result of revaluing our deferred tax assets at the newly enacted rate, of which $1.0 million was attributable to the non-controlling interest.

        Significant components of the Company's deferred tax assets and deferred tax liabilities consisted of the following:

	As of December 31,
(in thousands of dollars)	2015			2014
Deferred tax assets
Net operating loss	$	9,414		$	8,223
Section 754 election tax basis adjustment		47,100			945
Alternative minimum tax credits		—			53
Other deferred tax asset		505			232
Total deferred tax assets		57,019			9,453
Deferred tax liabilities
Investment in consolidated subsidiary JEH		73,559			29,307
Noncurrent state deferred tax liability		4,099			7,449
Total deferred tax liabilities		77,658			36,756
Net deferred tax assets (liabilities)		(20,639	)		(27,303	)
Valuation allowance		(2,333	)		—
Net deferred tax assets (liabilities)	$	(22,972	)	$	(27,303	)

        The Company has a federal net operating loss carry-forward totaling $24.8 million and state net operating loss carry-forward of $19.5 million, both of which expire between 2033 and 2035. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2015, we have a valuation allowance of $2.3 million as a result of management's assessment of the realizability of deferred tax assets in Oklahoma. Management believes that there will be sufficient future taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards.

        Separate federal and state income tax returns are filed for Jones Energy, Inc. and Jones Energy Holdings, LLC. JEH's Texas franchise tax returns are subject to audit for 2011 through 2015. The tax years 2012 through 2015 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Internal Revenue Service is currently examining the 2013 federal partnership income tax return for JEH.

        Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2015, 2014 and 2013 there was no material liability or expense for the periods then ended recorded for payments of interest and penalties associated with uncertain tax positions or material unrecognized tax positions and the Company's unrecognized tax benefits were not material.

Tax Receivable Agreement

        In connection with the IPO, the Company entered into a Tax Receivable Agreement (the "TRA") which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company's Class B common stock held by those owners for shares of the Company's Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings. At the time of an exchange, the company records a liability to reflect the future payments under the TRA.

        The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company's payments under the TRA constituting imputed interest. In the event that the Company records a valuation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as the payment of the TRA liability is dependent on the realizability of the deferred tax assets. As of December 31, 2015, the amount of the TRA liability was reduced by $2.0 million as a result of the valuation allowance recorded against the Company's deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

        As of December 31, 2015 and 2014 the Company had recorded a TRA liability of $38.1 million and $0.8 million, respectively, for the estimated payments that will be made to the pre-IPO members who have exchanged shares along with corresponding deferred tax assets, net of valuation allowance, of $44.8 million and $0.9 million, respectively, as a result of the increase in tax basis generated arising from such exchanges. The increase in the TRA liability was primarily driven by the exchange of 5 million JEH Units and Class B shares of common stock by Metalmark Captial in May of 2015.

        As of December 31, 2015, the Company had not made any payments under the TRA to pre-IPO members who have exchanged JEH units and Class B common stock for Class A common stock. The Company does not anticipate making a material payment under the TRA in 2016.

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Earnings per Share

12 Months Ended

Dec. 31, 2015

Earnings per Share

Earnings per Share

12. Earnings per Share

        Basic earnings per share ("EPS") is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. Awards of nonvested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the twelve months ended December 31, 2015, 757,245 restricted stock shares, 67,380 restricted stock units and 539,188 performance units were excluded from the calculation as they would have had an anti-dilutive effect. For the twelve months ended December 31, 2014, 27,430 restricted stock shares, 54,656 restricted stock units and 192,998 performance units were excluded from the calculation as they would have had an anti-dilutive effect. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS. 2014 is calculated using the twelve months ended December 31, 2014. 2013 is calculated for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

Basic Earnings per Share

(in thousands, except per share data)	2015			2014		2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic		26,816			12,526		12,500
Weighted-average number of shares of Class A common stock—diluted		26,816			12,535		12,500
Earnings (loss) per share:
Basic	$	(0.09	)	$	3.28	$	(0.17	)
Diluted	$	(0.09	)	$	3.28	$	(0.17	)

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Related Parties

12 Months Ended

Dec. 31, 2015

Related Parties

Related Parties

13. Related Parties

Related Party Transactions

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, ("Monarch"), under which Monarch has the first right to gather the natural gas the Company produces from dedicated properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted for gas. The Company produced approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014 and 0.8 MMBoe of natural gas and NGLs for the year ended December 31, 2013, from the properties that became subject to the Monarch agreement. During the years ended December 31, 2014 and 2013, the Company recognized $37.0 million and $10.4 million, respectively, of revenue associated to the aforementioned natural gas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreement transferred from Monarch to Enable Midstream Partners LP, ("Enable"), an unaffiliated third-party. Prior to closing of the transfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year ended December 31, 2015 from the properties that became subject to the Monarch agreement for which the Company recognized $10.6 million of revenue. The revenue, for all years mentioned, is recorded in Oil and gas sales on the Company's Consolidated Statement of Operations. The initial term of the agreement, which remains unchanged by the transfer to Enable, runs for 10 years from the effective date of September 1, 2013.

        At the time the Company entered into the 2013 Monarch agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company's outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital.

        In the year ended December 31, 2013, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was recorded in general and administration expense on the Company's Consolidated Statement of Operations. As a result of the IPO, this fee is no longer payable to Metalmark.

        In connection with the Company's entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. During the years ended December 31, 2015, 2014 and 2013, the Company amortized $2.0 million, $1.2 million, and $0.5 million, respectively, of the deferred revenue balance. This revenue is recorded in Other revenues on the Company's Consolidated Statement of Operations.

        Following the issuance of the $15 million Monarch equity interests, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity interests was distributed to certain of the pre-IPO owners, which included Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of December 31, 2015, equity interests in Monarch of $1.3 million are included in Other assets on the Company's Consolidated Balance Sheet. During the years ended December 31, 2015 and 2014, equity interests of $0.8 million and $0.5 million, respectively, were distributed to management under the incentive plan. The Company recognized expense of $0.5 million, $0.8 million, and $0.3 million during the years ended December 31, 2015, 2014, and 2013, respectively, in connection with the incentive plan.

        In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company did not incur or capitalize any costs associated with the construction of the pipeline. The Company did, however, incur gathering fees of $0.4 million which were paid to Monarch Oil Pipeline LLC associated with the approximately 0.2 MMBoe of oil production transported under the agreement for the year ended December 31, 2015. These costs are recorded as an offset to Oil and gas sales in the Company's Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company's Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third-parties, after passing through the gathering and transportation system. The Company has reserved capacity of up to 12,000 barrels per day on the system with the potential to increase throughput at a future date. The audit committee of the Board reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

        In May 2015, the Company received a $0.7 million cash distribution associated with its equity interests in Monarch, which was accounted for following the cost method. The initial cash distribution from Monarch was treated as dividend income and is recorded in Other income (expense).

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Commitments and Contingencies

14. Commitments and Contingencies

Lease obligations

        The Company leases approximately 43,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for all noncancellable operating leases extending beyond one year at December 31, 2015 are as follows:

(in thousands of dollars)
Years Ending December 31,
2016	$	945
2017		1,038
2018		1,101
2019		1,122
2020		377
Thereafter		—
	$	4,583

        Rent expense under operating leases was $1.6 million, $0.9 million and $0.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Litigation

        The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. The Company believes that the final disposition of such current matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

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Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events

Subsequent Events

15. Subsequent Events

        On November 18, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 9.25% senior notes due November 2023 (the "2023 Notes"), except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2023 Notes do not apply to the new 2023 Notes. On January 12, 2016, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $250 million outstanding principal amount of 2023 Notes for an equal amount of new 2023 Notes. The exchange offer expired on February 11, 2016. Tenders of $250 million aggregate principal amount, or 100%, of the 2023 Notes were received.

        In January and February 2016, through several open market and privately negotiated purchases, the Company purchased an aggregate principal amount of $170.5 million of its senior unsecured notes. As of February 29, 2016, the Company had purchased $70.5 million principal amount of its 2022 Notes for $27.1 million, and $100 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. As a result of these purchases, the Company had aggregate principal amount of senior unsecured notes outstanding of $579.5 million, outstanding borrowings under its revolving credit facility of $185 million, $325 million undrawn on its revolving credit facility, and $46 million in cash as of February 29, 2016.

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Subsidiary Guarantors

12 Months Ended

Dec. 31, 2015

Subsidiary Guarantors

Subsidiary Guarantors

16. Subsidiary Guarantors

        On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

        The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH's current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are immaterial.

        Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or a restricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any other guarantor.

        The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH's business. In accordance with JEH's limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

        As of December 31, 2015, the Company held approximately 49.4% of the economic interest in JEH, with the remaining 50.6% economic interest held by a group of investors that owned interests in JEH prior to the Company's IPO (the "Existing Owners"). The Existing Owners have no voting rights with respect to their economic interest in JEH.

        The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock. Pursuant to the Company's certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company's stockholders generally.

        In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Existing Owner held. Holders of the Company's Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company's stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

        The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2015

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,448	$	9,325	$	20		$	—		$	21,893
Restricted Cash		—			—		330		—			—			330
Accounts receivable, net
Oil and gas sales		—			—		19,292		—			—			19,292
Joint interest owners		—			—		11,314		—			—			11,314
Other		—			14,444		726		—			—			15,170
Commodity derivative assets		—			124,207		—		—			—			124,207
Other current assets		—			444		1,854		—			—			2,298
Intercompany receivable		12,866			1,161,997		—		—			(1,174,863	)		—
Total current assets		12,966			1,313,540		42,841		20			(1,174,863	)		194,504
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,635,766		—			—			1,635,766
Other property, plant and equipment, net		—			—		3,168		705			—			3,873
Commodity derivative assets		—			93,302		—		—			—			93,302
Other assets		—			17,714		253		—			—			17,967
Investment in subsidiaries		444,362			—		—		—			(444,362	)		—
Total assets	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	388	$	7,079	$	—		$	—		$	7,467
Oil and gas sales payable		—			—		32,408		—			—			32,408
Accrued liabilities		—			15,741		11,600		—			—			27,341
Commodity derivative liabilities		—			11		—		—			—			11
Asset retirement obligations		—			—		679		—			—			679
Intercompany payable		—			—		1,391,838		2,434			(1,394,272	)		—
Total current liabilities		—			16,140		1,443,604		2,434			(1,394,272	)		67,906
Long-term debt		—			847,912		—		—			—			847,912
Deferred revenue		—			11,417		—		—			—			11,417
Asset retirement obligations		—			—		20,301		—			—			20,301
Liability under tax receivable agreement		38,052			—		—		—			—			38,052
Deferred tax liabilities		19,280			3,692		—		—			—			22,972
Total liabilities		57,332			879,161		1,463,905		2,434			(1,394,272	)		1,008,560
Stockholders' / members' equity
Members' equity		—			545,395		218,123		(1,709	)		(761,809	)		—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding		31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding		31			—		—		—			—			31
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		363,723			—		—		—			—			363,723
Retained earnings		36,569			—		—		—			—			36,569
Stockholders' equity		399,996			545,395		218,123		(1,709	)		(761,809	)		399,996
Non-controlling interest		—			—		—		—			536,856			536,856
Total stockholders' equity		399,996			545,395		218,123		(1,709	)		(224,953	)		936,852
Total liabilities and stockholders' equity	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2014

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	1,000	$	12,436	$	30		$	—		$	13,566
Restricted Cash		—			—		149		—			—			149
Accounts receivable, net
Oil and gas sales		—			—		51,482		—			—			51,482
Joint interest owners		—			—		41,761		—			—			41,761
Other		102			8,788		3,622		—			—			12,512
Commodity derivative assets		—			121,519		—		—			—			121,519
Other current assets		—			451		2,923		—			—			3,374
Intercompany receivable		4,164			1,203,978		—		—			(1,208,142	)		—
Total current assets		4,366			1,335,736		112,373		30			(1,208,142	)		244,363
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,638,860		—			—			1,638,860
Other property, plant and equipment, net		—			—		3,252		796			—			4,048
Commodity derivative assets		—			87,055		—		—			—			87,055
Other assets		—			20,098		254		—			—			20,352
Deferred tax assets		171			—		—		—			—			171
Investment in subsidiaries		233,908			—		—		—			(233,908	)		—
Total assets	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	288	$	136,049	$	—		$	—		$	136,337
Oil and gas sales payable		—			—		70,469		—			—			70,469
Accrued liabilities		—			8,914		10,487		—			—			19,401
Asset retirement obligations		—			—		3,074		—			—			3,074
Intercompany payable		—			—		1,209,630		2,328			(1,211,958	)		—
Total current liabilities		—			9,202		1,429,709		2,328			(1,211,958	)		229,281
Long-term debt		—			860,000		—		—			—			860,000
Deferred revenue		—			13,377		—		—			—			13,377
Commodity derivative liabilities		—			28		—		—			—			28
Asset retirement obligations		—			—		10,536		—			—			10,536
Liability under tax receivable agreement		803			—		—		—			—			803
Deferred tax liabilities		20,237			7,237		—		—			—			27,474
Total liabilities		21,040			889,844		1,440,245		2,328			(1,211,958	)		1,141,499
Stockholders' / members' equity
Members' equity		—			553,045		314,494		(1,502	)		(866,037	)		—
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding		13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,719,499 shares issued and outstanding		37			—		—		—			—			37
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		178,763			—		—		—			—			178,763
Retained earnings		38,950			—		—		—			—			38,950
Stockholders' equity		217,405			553,045		314,494		(1,502	)		(866,037	)		217,405
Non-controlling interest		—			—		—		—			635,945			635,945
Total stockholders' equity		217,405			553,045		314,494		(1,502	)		(230,092	)		853,350
Total liabilities and stockholders' equity	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	194,555		$	—		$	—		$	194,555
Other revenues		—			1,960			884			—			—			2,844
Total operating revenues		—			1,960			195,439			—			—			197,399
Operating costs and expenses
Lease operating		—			—			41,027			—			—			41,027
Production and ad valorem taxes		—			—			12,130			—			—			12,130
Exploration		—			—			6,551			—			—			6,551
Depletion, depreciation and amortization		—			—			205,407			91			—			205,498
Accretion of ARO liability		—			—			1,087			—			—			1,087
General and administrative		—			13,565			19,707			116			—			33,388
Other operating		—			—			4,188			—			—			4,188
Total operating expenses		—			13,565			290,097			207			—			303,869
Operating income (loss)		—			(11,605	)		(94,658	)		(207	)		—			(106,470	)
Other income (expense)
Interest expense		—			(59,991	)		(1,298	)		—			—			(61,289	)
Net gain on commodity derivatives		—			158,753			—			—			—			158,753
Other income (expense)		1,984			(4,832	)		(4	)		—			—			(2,852	)
Other income (expense), net		1,984			93,930			(1,302	)		—			—			94,612
Income (loss) before income tax		1,984			82,325			(95,960	)		(207	)		—			(11,858	)
Equity interest in income		(4,728	)		—			—			—			4,728			—
Income tax provision
Current		—			113			—			—			—			113
Deferred		(363	)		(2,531	)		—			—			—			(2,894	)
Total Income tax provision (benefit)		(363	)		(2,418	)		—			—			—			(2,781	)
Net income (loss)		(2,381	)		84,743			(95,960	)		(207	)		4,728			(9,077	)
Net income (loss) attributable to non-controlling interests		—			—			—			—			(6,696	)		(6,696	)
Net income (loss) attributable to controlling interests	$	(2,381	)	$	—		$	—		$	—		$	—		$	(2,381	)

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	378,401		$	—		$	—		$	378,401
Other revenues		—		1,154			1,042			—			—			2,196
Total operating revenues		—		1,154			379,443			—			—			380,597
Operating costs and expenses
Lease operating		—		—			37,760			—			—			37,760
Production and ad valorem taxes		—		—			22,556			—			—			22,556
Exploration		—		—			3,453			—			—			3,453
Depletion, depreciation and amortization		—		—			181,578			91			—			181,669
Accretion of ARO liability		—		—			770			—			—			770
General and administrative		—		4,493			21,181			89			—			25,763
Other operating		—		—			—			—			—			—
Total operating expenses		—		4,493			267,298			180			—			271,971
Operating income (loss)		—		(3,339	)		112,145			(180	)		—			108,626
Other income (expense)
Interest expense		—		(37,295	)		(1,510	)		—			—			(38,805	)
Net gain on commodity derivatives		—		189,641			—			—			—			189,641
Other income (expense)		—		(7,921	)		297			—			—			(7,624	)
Other income (expense), net		—		144,425			(1,213	)		—			—			143,212
Income (loss) before income tax		—		141,086			110,932			(180	)		—			251,838
Equity interest in income		63,197		—			—			—			(63,197	)		—
Income tax provision
Current		53		—			—			—			—			53
Deferred		22,008		4,157			—			—			—			26,165
Total income tax provision		22,061		4,157			—			—			—			26,218
Net income (loss)		41,136		136,929			110,932			(180	)		(63,197	)		225,620
Net income (loss) attributable to non-controlling interests		—		—			—			—			184,484			184,484
Net income (loss) attributable to controlling interests	$	41,136	$	—		$	—		$	—		$	—		$	41,136

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues		—			469			637			—			—		1,106
Total operating revenues		—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating		—			—			25,129			—			—		25,129
Production and ad valorem taxes		—			—			15,517			—			—		15,517
Exploration		—			—			16,125			—			—		16,125
Depletion, depreciation and amortization		—			—			114,046			90			—		114,136
Accretion of ARO liability		—			—			608			—			—		608
General and administrative		—			4,154			27,490			258			—		31,902
Other operating		—			—			—			—			—		—
Total operating expenses		—			4,154			198,915			348			—		203,417
Operating income (loss)		—			(3,685	)		59,785			(348	)		—		55,752
Other income (expense)
Interest expense		—			(26,288	)		(1,121	)		—			—		(27,409	)
Net gain on commodity derivatives		—			(2,566	)		—			—			—		(2,566	)
Other income (expense)		—			(3,365	)		41			(119	)		—		(3,443	)
Other income (expense), net		—			(32,219	)		(1,080	)		(119	)		—		(33,418	)
Income (loss) before income tax		—			(35,904	)		58,705			(467	)		—		22,334
Equity interest in income		(3,400	)		—			—			—			3,400		—
Income tax provision
Current		85			—			—			—			—		85
Deferred		(1,299	)		1,143			—			—			—		(156	)
Total income tax provision		(1,214	)		1,143			—			—			—		(71	)
Net income (loss)		(2,186	)		(37,047	)		58,705			(467	)		3,400		22,405
Net income (loss) attributable to non-controlling interests		—			—			—			—			24,591		24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	$	—		$	—		$	—		$	—	$	(2,186	)

Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,381	)	$	84,743		$	(95,960	)	$	(207	)	$	4,728		$	(9,077	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(120,398	)		(202,359	)		405,395			197			(4,728	)		78,107
Net cash (used in) / provided by operations		(122,779	)		(117,616	)		309,435			(10	)		—			69,030
Cash flows from investing activities
Additions to oil and gas properties		—			—			(311,305	)		—			—			(311,305	)
Proceeds from sales of assets		—			—			41			—			—			41
Acquisition of other property, plant and equipment		—			—			(1,101	)		—			—			(1,101	)
Current period settlements of matured derivative contracts		—			144,145			—			—			—			144,145
Change in restricted cash		—			—			(181	)		—			—			(181	)
Net cash (used in) / provided by investing		—			144,145			(312,546	)		—			—			(168,401	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			85,000			—			—			—			85,000
Repayment under long-term debt		—			(335,000	)		—			—			—			(335,000	)
Proceeds from senior notes		—			236,475			—			—			—			236,475
Payment of debt issuance costs		—			(1,556	)		—			—			—			(1,556	)
Proceeds from sale of common stock		122,779			—			—			—			—			122,779
Net cash (used in) / provided by financing		122,779			(15,081	)		—			—			—			107,698
Net increase (decrease) in cash		—			11,448			(3,111	)		(10	)		—			8,327
Cash
Beginning of period		100			1,000			12,436			30			—			13,566
End of period	$	100		$	12,448		$	9,325		$	20		$	—		$	21,893

Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	41,136		$	136,929		$	110,932		$	(180	)	$	(63,197	)	$	225,620
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(40,778	)		(326,859	)		344,103			140			63,197			39,803
Net cash (used in) / provided by operations		358			(189,930	)		455,035			(40	)		—			265,423
Cash flows from investing activities
Additions to oil and gas properties		—			—			(474,619	)		—			—			(474,619	)
Net adjustments to purchase price of properties acquired		—			—			15,709			—			—			15,709
Proceeds from sales of assets		—			—			448			—			—			448
Acquisition of other property, plant and equipment		—			—			(1,683	)		—			—			(1,683	)
Current period settlements of matured derivative contracts		—			(3,654	)		—			—			—			(3,654	)
Change in restricted cash		—			—			(104	)		—			—			(104	)
Net cash (used in) / provided by investing		—			(3,654	)		(460,249	)		—			—			(463,903	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			170,000			—			—			—			170,000
Repayment under long-term debt		—			(468,000	)		—			—			—			(468,000	)
Proceeds from senior notes		—			500,000			—			—			—			500,000
Purchases of treasury stock		(358	)		—			—			—			—			(358	)
Payment of debt issuance costs		—			(13,416	)		—			—			—			(13,416	)
Net cash (used in) / provided by financing		(358	)		188,584			—			—			—			188,226
Net increase (decrease) in cash		—			(5,000	)		(5,214	)		(40	)		—			(10,254	)
Cash
Beginning of period		100			6,000			17,650			70			—			23,820
End of period	$	100		$	1,000		$	12,436		$	30		$	—		$	13,566

Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities		2,286			(189,393	)		315,942			733			(3,400	)		126,168
Net cash (used in) / provided by operations		100			(226,440	)		374,647			266			—			148,573
Cash flows from investing activities
Investment in subsidiary		(172,481	)		—			—			—			172,481			—
Additions to oil and gas properties		—			—			(197,618	)		—			—			(197,618	)
Acquisitions of properties		—			—			(178,173	)		—			—			(178,173	)
Proceeds from sales of assets		—			—			963			644			—			1,607
Acquisition of other property, plant and equipment		—			—			(724	)		(910	)		—			(1,634	)
Current period settlements of matured derivative contracts		—			7,586			—			—			—			7,586
Change in restricted cash		—			—			(45	)		—			—			(45	)
Net cash (used in) / provided by investing		(172,481	)		7,586			(375,597	)		(266	)		172,481			(368,277	)
Cash flows from financing activities
Proceeds from investment in JEI		—			172,481			—			—			(172,481	)		—
Proceeds from issuance of long-term debt		—			220,000			—			—			—			220,000
Repayment under long-term debt		—			(172,000	)		—			—			—			(172,000	)
Proceeds from sale of common stock		172,481			—			—			—			—			172,481
Payment of debt issuance costs		—			(683	)		—			—			—			(683	)
Net cash (used in) / provided by financing		172,481			219,798			—			—			(172,481	)		219,798
Net increase (decrease) in cash		100			944			(950	)		—			—			94
Cash
Beginning of period		—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		$	—		$	23,820

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Significant Accounting Policies

Basis of Presentation

Basis of Presentation

        The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for December 31, 2015 and 2014 and the results of the operations and the cash flows for each of the three years in the period ended December 31, 2014 include the Company and all of its subsidiaries.

        Certain prior period amounts have been reclassified to conform to the current presentation.

Segment Information

Segment Information

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

Use of Estimates

Use of Estimates

        In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

        Significant assumptions are required in the valuation of proved and unproved oil and natural gas reserves, which affect the Company's estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in the Company's estimates of the net gain or loss on commodity derivative assets and liabilities, fair value associated with business combinations, and asset retirement obligations ("ARO").

Cash

Cash

        Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions it does business with, and believes the Company's risk is not significant.

Accounts Receivable

Accounts Receivable

        Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consists at December 31, 2015 and at December 31, 2014 of derivative positions not settled as of the balance sheet date and severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management's best estimate of the amounts that may not be collected. As of December 31, 2015 and 2014, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

Concentration of Risk

        Substantially all of the Company's accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company's overall credit risk in that these entities may be affected similarly by changes in economic and other conditions, including declines in commodity prices. As of December 31, 2015, 68% of Accounts receivable—Oil and gas sales are due from four purchasers and 80% of Accounts receivable—Joint interest owners are due from five working interest owners. As of December 31, 2014, 70% of Accounts receivable—Oil and gas sales were due from five purchasers and 67% of Accounts receivable—Joint interest owners were due from five working interest owners. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales were due from eight purchasers and 77% of Accounts receivable—Joint interest owners were due from five working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company's financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

Dependence on Major Customers

        The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2015, the largest purchasers were Valero Energy Corp. ("Valero"), ETC Field Services LLC, Plains Marketing LP ("Plains Marketing"), NGL Energy Partners LP, and Unimark LLC, which accounted for approximately 18%, 17%, 16%, 15% and 7% of consolidated oil and gas sales, respectively. During the year ended December 31, 2014, the largest purchasers were Valero Energy Corp. ("Valero"), NGL Energy Partners LP, PVR Midstream LLC ("PVR Midstream"), Plains Marketing LP ("Plains Marketing"), and Monarch Natural Gas LLC which accounted for approximately 22%, 12%, 12%, 10% and 10% of consolidated oil and gas sales, respectively. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria Energy Group Ltd. ("Mercuria"), Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively.

        Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company's purchasers are credit worthy.

Dependence on Suppliers

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there can be an imbalance between the supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to work interruptions or stoppages, the Company could be materially and adversely affected. Management believes that there are adequate alternative providers of drilling and completion services although it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

Oil and Gas Properties

Oil and Gas Properties

        The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

        Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

        The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use.

        On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

        Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over the life of proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

        The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk- adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

        The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company's unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company's current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration and development activity by other companies on adjacent blocks.

        On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property, Plant and Equipment

Other Property, Plant and Equipment

        Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years.

Oil and Gas Sales Payable

Oil and Gas Sales Payable

        Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

Commodity Derivatives

Commodity Derivatives

        The Company records its commodity derivative instruments on the Consolidated Balance Sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the years ended December 31, 2015, 2014 and 2013, the Company elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

        Although the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company's exposure to fluctuations in commodity prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) on the Consolidated Statement of Operations. See Note 7, "Fair Value Measurement," for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

Asset Retirement Obligations

        The Company's asset retirement obligations ("ARO") consist of future plugging and abandonment expenses on oil and natural gas properties. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long- lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments.

Revenue Recognition

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are valued at the estimated sales price and recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the "sales method" of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. Any such imbalances were not significant as of December 31, 2015.

Income Taxes

Income Taxes

        Following its IPO on July 29, 2013, the Company began recording a federal and state income tax liability associated with its status as a corporation. No provision for federal income taxes was recorded prior to the IPO because the taxable income or loss was includable in the income tax returns of the individual partners and members. The Company is also subject to state income taxes. The State of Texas includes in its tax system a franchise tax applicable to the Company and an accrual for franchise taxes is included in the financial statements when appropriate.

        Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

        The Company records a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by the Company and may be challenged by the taxation authorities. The Company follows a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. The Company's policy is to include any interest and penalties recorded on uncertain tax positions as a component of income tax expense. The Company's unrecognized tax benefits or related interest and penalties are immaterial.

Comprehensive Income

Comprehensive Income

        The Company has no elements of comprehensive income other than net income.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

        In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers," which creates a new topic in the ASC, topic 606, "Revenue from Contracts with Customers." This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14 which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. We are currently evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements.

        In January 2015, the FASB issued ASU No. 2015- 01, Income Statement—Extraordinary and Unusual Items. This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30) ("Update 2015-15"), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

        In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. The guidance is effective for financial statements issued for annual periods beginning after 15 December 2016, and interim periods within those annual periods. Early adoption is permitted. The guidance may be adopted on either a prospective or retrospective basis. The Company has chosen to early adopt ASU No. 2015-17 for the period ended December 31, 2015. Changes to the balance sheet have been applied on a retrospective basis. Adoption did not have a material impact on the financial position, cash flows or results of operations.

        In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

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Organization and Description of Business (Tables)

12 Months Ended

Dec. 31, 2015

Organization and Description of Business

Revised Consolidated Balance Sheet and Consolidated Statements of Operations

Consolidated Balance Sheet:

	December 31, 2014								December 31, 2014
				Production tax		Exchange of Class B shares
(in thousands of dollars)	As Reported								As Revised
Accounts Receivable, Oil and gas sales	$	49,861		$	1,621		—		$	51,482
Deferred tax liabilities	$	27,330	(1)	$	144		—		$	27,474
Additional paid in capital	$	177,133			—	$	1,630		$	178,763
Retained earnings	$	38,682		$	268		—		$	38,950
Non-controlling interest	$	636,366		$	1,209	$	(1,630	)	$	635,945

(1)Certain prior period amounts have been reclassified to conform to the current presentation.

Consolidated Statements of Operations—for the twelve months ended:

	December 31, 2014						December 31, 2014
				Production tax
(in thousands except per share data)	As Reported						As Revised
Production and ad valorem taxes	$	24,177	(1)	$	(1,621	)	$	22,556
Income tax provision (benefit)	$	26,074		$	144		$	26,218
Net income (loss)	$	224,143		$	1,477		$	225,620
Net income (loss) attributable to non-controlling interests	$	183,275		$	1,209		$	184,484
Net income (loss) attributable to controlling interests	$	40,868		$	268		$	41,136
Earnings (Loss) per share:
Basic	$	3.26		$	0.02		$	3.28
Diluted	$	3.26		$	0.02		$	3.28

(1)Certain prior period amounts have been reclassified to conform to the current presentation.

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Properties, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Properties, Plant and Equipment

Schedule of oil and gas properties

(in thousands of dollars)	2015			2014
Mineral interests in properties
Unproved	$	75,308		$	94,526
Proved		1,031,669			1,001,194
Wells and equipment and related facilities		1,289,323			1,094,202
		2,396,300			2,189,922
Less: Accumulated depletion and impairment		(760,534	)		(551,062	)
Net oil and gas properties	$	1,635,766		$	1,638,860

Schedule of other property, plant and equipment

(in thousands of dollars)	2015			2014
Leasehold improvements	$	1,260		$	1,218
Furniture, fixtures, computers and software		4,090			3,727
Vehicles		1,537			988
Aircraft		910			910
Other		247			219
		8,044			7,062
Less: Accumulated depreciation and amortization		(4,171	)		(3,014	)
Net other property, plant and equipment	$	3,873		$	4,048

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Acquisition of Properties (Tables)

12 Months Ended

Dec. 31, 2015

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties
Unproved	$	32,964
Proved		147,024
Asset retirement obligations		(824	)
Total purchase price	$	179,164

Schedule of unaudited pro forma results of operations

			Year Ended December 31, 2013
	Post Acquisition(1)
(in thousands of dollars)			Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses		291		229,648
Operating income		1,074		79,125
Net income		1,074		45,778

(1)Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Long-Term Debt

Summary of long-term debt

(in thousands of dollars)	December 31, 2015			December 31, 2014
Revolver	$	110,000		$	360,000
2022 Notes		500,000			500,000
2023 Notes		250,000			—
Total principal amount		860,000			860,000
Less: unamortized discount		(12,088	)		—
Total carrying amount	$	847,912		$	860,000

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities

Schedule of various commodity derivatives in place to offset uncertain price fluctuations that could affect the entity's future operations

	December 31, 2015
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.16
	Barrels per month		54,000			194,000			97,119		June 2019
Natural gas swaps	Exercise price	$	3.22		$	6.45		$	4.25
	mmbtu per month		700,000			1,640,000			1,042,857		June 2019
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.18	)
	mmbtu per month		1,190,000			1,730,000			1,360,833		December 2016
Natural gas liquids swaps	Exercise price	$	8.90		$	95.24		$	32.62
	Barrels per month		2,000			112,000			51,792		December 2017

	December 31, 2014
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	75.05		$	100.95		$	84.20
	Barrels per month		45,000			184,054			113,852		December 2018
Natural gas swaps	Exercise price	$	3.37		$	6.45		$	4.40
	mmbtu per month		710,000			1,772,584			1,175,275		December 2018
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.21	)
	mmbtu per month		320,000			980,000			716,667		March 2016
Natural gas liquids swaps	Exercise price	$	8.09		$	95.24		$	42.46
	Barrels per month		2,000			143,000			50,444		December 2017

Schedule of commodity derivative contracts, assets, netted on the Consolidated Balance Sheet

(in thousands of dollars)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities		(538	)		527			(11	)		—		(11	)
December 31, 2014
Commodity derivative contracts
Assets	$	208,646		$	(72	)	$	208,574		$	—	$	208,574
Liabilities		(100	)		72			(28	)		—		(28	)

Schedule of commodity derivative contracts, liabilities, netted on the Consolidated Balance Sheet

(in thousands of dollars)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities		(538	)		527			(11	)		—		(11	)
December 31, 2014
Commodity derivative contracts
Assets	$	208,646		$	(72	)	$	208,574		$	—	$	208,574
Liabilities		(100	)		72			(28	)		—		(28	)

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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Measurement

Schedule of financial instruments carried at fair value

	December 31, 2015
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets		—		93,302		—		93,302
Current liabilities		—		11		—		11
Long-term liabilities		—		—		—		—

	December 31, 2014
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	120,604	$	915	$	121,519
Long-term assets		—		85,162		1,893		87,055
Current liabilities		—		—		—		—
Long-term liabilities		—		—		28		28

Schedule of quantitative information about Level 3 inputs used in the fair value measurement, assets

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value (000's)		Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	1,428	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$8.90 - $47.25 per barrel

Schedule of changes in fair value of Level 3 financial instruments

(in thousands of dollars)
Balance at December 31, 2013, net	$	(1,235	)
Purchases		668
Settlements		476
Transfers into Level 3		(265	)
Transfers to Level 2		332
Changes in fair value		2,804
Balance at December 31, 2014, net		2,780
Purchases		648
Settlements		(960	)
Transfers into Level 3		—
Transfers to Level 2		(1,367	)
Changes in fair value		327
Balance at December 31, 2015, net	$	1,428

Schedule of fair value of financial instruments that are not recorded at fair value in the consolidated financial statements

	December 31, 2015				December 31, 2014
(in thousands of dollars)	Principal Amount		Fair Value		Principal Amount		Fair Value
Debt:
Revolver	$	110,000	$	110,000	$	360,000	$	360,000
2022 Notes		500,000		260,000		500,000		384,375
2023 Notes		250,000		153,283		—		—

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligations

Summary of the Company's ARO

(in thousands of dollars)	2015			2014
ARO liability at beginning of year	$	13,610		$	10,963
Liabilities incurred(1)		6,349			1,995
Accretion of ARO liability		1,087			770
Liabilities settled due to sale of related properties		(19	)		(109	)
Liabilities settled due to plugging and abandonment		(69	)		(55	)
Change in estimate		22			46
ARO liability at end of year		20,980			13,610
Less: Current portion of ARO at end of year		(679	)		(3,074	)
Total long-term ARO at end of year	$	20,301		$	10,536

(1)Includes $4.7 million to correct immaterial errors originating in 2013 and 2014. In addition to the balance sheet impact noted, Accretion of ARO liability of $0.2 million and Depletion, depreciation, and amortization of $0.6 million were recognized in our statement of operations during the fourth quarter of 2015 as a correcting adjustment. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

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Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Stock-based Compensation

Schedule of assumptions used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense

	2015 Performance Unit Awards			2014 Performance Unit Awards
Stock Price(1)	$	10.11		$	17.07
Beginning Average Stock Price(2)	$	11.56		$	14.78
Expected Volatility(3)		55.13	%		46.95	%
Risk-Free Rate of Return(4)		0.79	%		0.61	%

(1)Based on the closing price of Jones Energy, Inc. Class A common stock on April 29, 2015 and May 20, 2014.

(2)Based on the 10 trading days immediately prior to the beginning of the performance period.

(3)For the 2015 award this is based on the average historical volatilities over the most recent 2.67-year period for the Company and each peer company using daily stock prices through April 29, 2015. The measurement period reflects the 2.67 years remaining in the performance period as of the grant date.

For the 2014 award this is based on the average historical volatilities over the most recent 2.62-year period for the Company and each peer company using daily stock prices through May 20, 2014. The measurement period reflects the 2.62 years remaining in the performance period as of the grant date.

(4)Based on the yield curve of U.S. Treasury rates as of April 29, 2015 and May 20, 2014.

Management Unit Awards

Stock-based Compensation

Summary of information related to the Units/shares or awards

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		274,385		$	15.00
Granted		1,909		$	15.00
Forfeited		(1,909	)	$	15.00
Vested		(85,030	)	$	15.00
Unvested at December 31, 2015		189,355		$	15.00

Restricted Stock Unit Awards

Stock-based Compensation

Summary of information related to the Units/shares or awards

	Restricted Stock Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		324,897		$	17.33
Granted		572,939		$	9.58
Forfeited		(14,995	)	$	12.84
Vested		(125,596	)	$	16.75
Unvested at December 31, 2015		757,245		$	11.65

Performance Unit Awards

Stock-based Compensation

Summary of information related to the Units/shares or awards

	Performance Unit Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		192,998		$	21.65
Granted		361,422		$	10.27
Forfeited		—			—
Vested		(15,232	)	$	14.59
Unvested at December 31, 2015		539,188		$	14.22

Restricted Stock Awards

Stock-based Compensation

Summary of information related to the Units/shares or awards

	Restricted Stock Awards			Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2014		27,430		$	18.77
Granted		67,380		$	7.30
Forfeited		—			—
Vested		(27,430	)	$	18.77
Unvested at December 31, 2015		67,380		$	7.30

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Taxes

Schedule of income tax provision

	Year Ended December 31,
(in thousands of dollars)	2015			2014		2013
Current tax expense:
Federal	$	—		$	53	$	85
State		113			—		—
Total current expense		113			53		85
Deferred tax expense (benefit):
Federal		(1,137	)		22,140		(1,260	)
State		(1,757	)		4,025		1,104
Total deferred expense (benefit)		(2,894	)		26,165		(156	)
Total tax expense (benefit)		(2,781	)	$	26,218	$	(71	)
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819	$	(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399		1,152
Total income tax expense (benefit)		(2,781	)	$	26,218	$	(71	)

Schedule of reconciliation of the Company's provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate

(in thousands of dollars)	2015			2014			2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	(11,858	)	$	251,838		$	22,334
Statutory rate		35	%		35	%		35	%
Income tax expense (benefit) computed at statutory rate	$	(4,150	)	$	88,144		$	7,817
Less: Non-controlling interests		2,911			(65,759	)		(9,009	)
Income tax expense (benefit) attributable to controlling interests		(1,239	)		22,385			(1,192	)
State and local income taxes, net of federal benefit		(1,011	)		626			(49	)
Reduction of TRA liability		(694	)		—			—
Equity compensation, shortfall		338			—			—
Change in enacted rate		(650	)		—			—
Change in valuation allowance		2,333			—			—
Other		(237	)		(192	)		18
Tax expense (benefit) attributable to controlling interests		(1,160	)		22,819			(1,223	)
Tax expense attributable to non-controlling interests		(1,621	)		3,399			1,152
Total income tax expense (benefit)(1)	$	(2,781	)	$	26,218		$	(71	)

(1)Deferred tax expense of the year ended December 31, 2015 includes the correction of an immaterial error from the year ended December 31, 2014, whereby deferred tax expense was overstated in 2014 and understated in 2015 by $0.9 million. We have determined that this adjustment is not material to the consolidated financial statements of any period presented.

Schedule of significant components of the Company's deferred tax assets and deferred tax liability

	As of December 31,
(in thousands of dollars)	2015			2014
Deferred tax assets
Net operating loss	$	9,414		$	8,223
Section 754 election tax basis adjustment		47,100			945
Alternative minimum tax credits		—			53
Other deferred tax asset		505			232
Total deferred tax assets		57,019			9,453
Deferred tax liabilities
Investment in consolidated subsidiary JEH		73,559			29,307
Noncurrent state deferred tax liability		4,099			7,449
Total deferred tax liabilities		77,658			36,756
Net deferred tax assets (liabilities)		(20,639	)		(27,303	)
Valuation allowance		(2,333	)		—
Net deferred tax assets (liabilities)	$	(22,972	)	$	(27,303	)

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Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings per Share

Schedule of calculation of the basic and diluted weighted-average shares and EPS

(in thousands, except per share data)	2015			2014		2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,381	)	$	41,136	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic		26,816			12,526		12,500
Weighted-average number of shares of Class A common stock—diluted		26,816			12,535		12,500
Earnings (loss) per share:
Basic	$	(0.09	)	$	3.28	$	(0.17	)
Diluted	$	(0.09	)	$	3.28	$	(0.17	)

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Schedule of future minimum payments for noncancellable operating leases extending beyond one year

(in thousands of dollars)
Years Ending December 31,
2016	$	945
2017		1,038
2018		1,101
2019		1,122
2020		377
Thereafter		—
	$	4,583

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Subsidiary Guarantors (Tables)

12 Months Ended

Dec. 31, 2015

Subsidiary Guarantors

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet

December 31, 2015

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,448	$	9,325	$	20		$	—		$	21,893
Restricted Cash		—			—		330		—			—			330
Accounts receivable, net
Oil and gas sales		—			—		19,292		—			—			19,292
Joint interest owners		—			—		11,314		—			—			11,314
Other		—			14,444		726		—			—			15,170
Commodity derivative assets		—			124,207		—		—			—			124,207
Other current assets		—			444		1,854		—			—			2,298
Intercompany receivable		12,866			1,161,997		—		—			(1,174,863	)		—
Total current assets		12,966			1,313,540		42,841		20			(1,174,863	)		194,504
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,635,766		—			—			1,635,766
Other property, plant and equipment, net		—			—		3,168		705			—			3,873
Commodity derivative assets		—			93,302		—		—			—			93,302
Other assets		—			17,714		253		—			—			17,967
Investment in subsidiaries		444,362			—		—		—			(444,362	)		—
Total assets	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	388	$	7,079	$	—		$	—		$	7,467
Oil and gas sales payable		—			—		32,408		—			—			32,408
Accrued liabilities		—			15,741		11,600		—			—			27,341
Commodity derivative liabilities		—			11		—		—			—			11
Asset retirement obligations		—			—		679		—			—			679
Intercompany payable		—			—		1,391,838		2,434			(1,394,272	)		—
Total current liabilities		—			16,140		1,443,604		2,434			(1,394,272	)		67,906
Long-term debt		—			847,912		—		—			—			847,912
Deferred revenue		—			11,417		—		—			—			11,417
Asset retirement obligations		—			—		20,301		—			—			20,301
Liability under tax receivable agreement		38,052			—		—		—			—			38,052
Deferred tax liabilities		19,280			3,692		—		—			—			22,972
Total liabilities		57,332			879,161		1,463,905		2,434			(1,394,272	)		1,008,560
Stockholders' / members' equity
Members' equity		—			545,395		218,123		(1,709	)		(761,809	)		—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding		31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding		31			—		—		—			—			31
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		363,723			—		—		—			—			363,723
Retained earnings		36,569			—		—		—			—			36,569
Stockholders' equity		399,996			545,395		218,123		(1,709	)		(761,809	)		399,996
Non-controlling interest		—			—		—		—			536,856			536,856
Total stockholders' equity		399,996			545,395		218,123		(1,709	)		(224,953	)		936,852
Total liabilities and stockholders' equity	$	457,328		$	1,424,556	$	1,682,028	$	725		$	(1,619,225	)	$	1,945,412

Condensed Consolidating Balance Sheet

December 31, 2014

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	1,000	$	12,436	$	30		$	—		$	13,566
Restricted Cash		—			—		149		—			—			149
Accounts receivable, net
Oil and gas sales		—			—		51,482		—			—			51,482
Joint interest owners		—			—		41,761		—			—			41,761
Other		102			8,788		3,622		—			—			12,512
Commodity derivative assets		—			121,519		—		—			—			121,519
Other current assets		—			451		2,923		—			—			3,374
Intercompany receivable		4,164			1,203,978		—		—			(1,208,142	)		—
Total current assets		4,366			1,335,736		112,373		30			(1,208,142	)		244,363
Oil and gas properties, net, at cost under the successful efforts method		—			—		1,638,860		—			—			1,638,860
Other property, plant and equipment, net		—			—		3,252		796			—			4,048
Commodity derivative assets		—			87,055		—		—			—			87,055
Other assets		—			20,098		254		—			—			20,352
Deferred tax assets		171			—		—		—			—			171
Investment in subsidiaries		233,908			—		—		—			(233,908	)		—
Total assets	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	—		$	288	$	136,049	$	—		$	—		$	136,337
Oil and gas sales payable		—			—		70,469		—			—			70,469
Accrued liabilities		—			8,914		10,487		—			—			19,401
Asset retirement obligations		—			—		3,074		—			—			3,074
Intercompany payable		—			—		1,209,630		2,328			(1,211,958	)		—
Total current liabilities		—			9,202		1,429,709		2,328			(1,211,958	)		229,281
Long-term debt		—			860,000		—		—			—			860,000
Deferred revenue		—			13,377		—		—			—			13,377
Commodity derivative liabilities		—			28		—		—			—			28
Asset retirement obligations		—			—		10,536		—			—			10,536
Liability under tax receivable agreement		803			—		—		—			—			803
Deferred tax liabilities		20,237			7,237		—		—			—			27,474
Total liabilities		21,040			889,844		1,440,245		2,328			(1,211,958	)		1,141,499
Stockholders' / members' equity
Members' equity		—			553,045		314,494		(1,502	)		(866,037	)		—
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding		13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,719,499 shares issued and outstanding		37			—		—		—			—			37
Treasury stock, at cost: 22,602 shares		(358	)		—		—		—			—			(358	)
Additional paid-in-capital		178,763			—		—		—			—			178,763
Retained earnings		38,950			—		—		—			—			38,950
Stockholders' equity		217,405			553,045		314,494		(1,502	)		(866,037	)		217,405
Non-controlling interest		—			—		—		—			635,945			635,945
Total stockholders' equity		217,405			553,045		314,494		(1,502	)		(230,092	)		853,350
Total liabilities and stockholders' equity	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849

Condensed Consolidating Statement of Operations

Condensed Consolidating Statement of Operations

Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	194,555		$	—		$	—		$	194,555
Other revenues		—			1,960			884			—			—			2,844
Total operating revenues		—			1,960			195,439			—			—			197,399
Operating costs and expenses
Lease operating		—			—			41,027			—			—			41,027
Production and ad valorem taxes		—			—			12,130			—			—			12,130
Exploration		—			—			6,551			—			—			6,551
Depletion, depreciation and amortization		—			—			205,407			91			—			205,498
Accretion of ARO liability		—			—			1,087			—			—			1,087
General and administrative		—			13,565			19,707			116			—			33,388
Other operating		—			—			4,188			—			—			4,188
Total operating expenses		—			13,565			290,097			207			—			303,869
Operating income (loss)		—			(11,605	)		(94,658	)		(207	)		—			(106,470	)
Other income (expense)
Interest expense		—			(59,991	)		(1,298	)		—			—			(61,289	)
Net gain on commodity derivatives		—			158,753			—			—			—			158,753
Other income (expense)		1,984			(4,832	)		(4	)		—			—			(2,852	)
Other income (expense), net		1,984			93,930			(1,302	)		—			—			94,612
Income (loss) before income tax		1,984			82,325			(95,960	)		(207	)		—			(11,858	)
Equity interest in income		(4,728	)		—			—			—			4,728			—
Income tax provision
Current		—			113			—			—			—			113
Deferred		(363	)		(2,531	)		—			—			—			(2,894	)
Total Income tax provision (benefit)		(363	)		(2,418	)		—			—			—			(2,781	)
Net income (loss)		(2,381	)		84,743			(95,960	)		(207	)		4,728			(9,077	)
Net income (loss) attributable to non-controlling interests		—			—			—			—			(6,696	)		(6,696	)
Net income (loss) attributable to controlling interests	$	(2,381	)	$	—		$	—		$	—		$	—		$	(2,381	)

Condensed Consolidating Statement of Operations

Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	378,401		$	—		$	—		$	378,401
Other revenues		—		1,154			1,042			—			—			2,196
Total operating revenues		—		1,154			379,443			—			—			380,597
Operating costs and expenses
Lease operating		—		—			37,760			—			—			37,760
Production and ad valorem taxes		—		—			22,556			—			—			22,556
Exploration		—		—			3,453			—			—			3,453
Depletion, depreciation and amortization		—		—			181,578			91			—			181,669
Accretion of ARO liability		—		—			770			—			—			770
General and administrative		—		4,493			21,181			89			—			25,763
Other operating		—		—			—			—			—			—
Total operating expenses		—		4,493			267,298			180			—			271,971
Operating income (loss)		—		(3,339	)		112,145			(180	)		—			108,626
Other income (expense)
Interest expense		—		(37,295	)		(1,510	)		—			—			(38,805	)
Net gain on commodity derivatives		—		189,641			—			—			—			189,641
Other income (expense)		—		(7,921	)		297			—			—			(7,624	)
Other income (expense), net		—		144,425			(1,213	)		—			—			143,212
Income (loss) before income tax		—		141,086			110,932			(180	)		—			251,838
Equity interest in income		63,197		—			—			—			(63,197	)		—
Income tax provision
Current		53		—			—			—			—			53
Deferred		22,008		4,157			—			—			—			26,165
Total income tax provision		22,061		4,157			—			—			—			26,218
Net income (loss)		41,136		136,929			110,932			(180	)		(63,197	)		225,620
Net income (loss) attributable to non-controlling interests		—		—			—			—			184,484			184,484
Net income (loss) attributable to controlling interests	$	41,136	$	—		$	—		$	—		$	—		$	41,136

Condensed Consolidating Statement of Operations

Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues		—			469			637			—			—		1,106
Total operating revenues		—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating		—			—			25,129			—			—		25,129
Production and ad valorem taxes		—			—			15,517			—			—		15,517
Exploration		—			—			16,125			—			—		16,125
Depletion, depreciation and amortization		—			—			114,046			90			—		114,136
Accretion of ARO liability		—			—			608			—			—		608
General and administrative		—			4,154			27,490			258			—		31,902
Other operating		—			—			—			—			—		—
Total operating expenses		—			4,154			198,915			348			—		203,417
Operating income (loss)		—			(3,685	)		59,785			(348	)		—		55,752
Other income (expense)
Interest expense		—			(26,288	)		(1,121	)		—			—		(27,409	)
Net gain on commodity derivatives		—			(2,566	)		—			—			—		(2,566	)
Other income (expense)		—			(3,365	)		41			(119	)		—		(3,443	)
Other income (expense), net		—			(32,219	)		(1,080	)		(119	)		—		(33,418	)
Income (loss) before income tax		—			(35,904	)		58,705			(467	)		—		22,334
Equity interest in income		(3,400	)		—			—			—			3,400		—
Income tax provision
Current		85			—			—			—			—		85
Deferred		(1,299	)		1,143			—			—			—		(156	)
Total income tax provision		(1,214	)		1,143			—			—			—		(71	)
Net income (loss)		(2,186	)		(37,047	)		58,705			(467	)		3,400		22,405
Net income (loss) attributable to non-controlling interests		—			—			—			—			24,591		24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	$	—		$	—		$	—		$	—	$	(2,186	)

Condensed Consolidating Statement of Cash Flows

[Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,381	)	$	84,743		$	(95,960	)	$	(207	)	$	4,728		$	(9,077	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(120,398	)		(202,359	)		405,395			197			(4,728	)		78,107
Net cash (used in) / provided by operations		(122,779	)		(117,616	)		309,435			(10	)		—			69,030
Cash flows from investing activities
Additions to oil and gas properties		—			—			(311,305	)		—			—			(311,305	)
Proceeds from sales of assets		—			—			41			—			—			41
Acquisition of other property, plant and equipment		—			—			(1,101	)		—			—			(1,101	)
Current period settlements of matured derivative contracts		—			144,145			—			—			—			144,145
Change in restricted cash		—			—			(181	)		—			—			(181	)
Net cash (used in) / provided by investing		—			144,145			(312,546	)		—			—			(168,401	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			85,000			—			—			—			85,000
Repayment under long-term debt		—			(335,000	)		—			—			—			(335,000	)
Proceeds from senior notes		—			236,475			—			—			—			236,475
Payment of debt issuance costs		—			(1,556	)		—			—			—			(1,556	)
Proceeds from sale of common stock		122,779			—			—			—			—			122,779
Net cash (used in) / provided by financing		122,779			(15,081	)		—			—			—			107,698
Net increase (decrease) in cash		—			11,448			(3,111	)		(10	)		—			8,327
Cash
Beginning of period		100			1,000			12,436			30			—			13,566
End of period	$	100		$	12,448		$	9,325		$	20		$	—		$	21,893

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	41,136		$	136,929		$	110,932		$	(180	)	$	(63,197	)	$	225,620
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(40,778	)		(326,859	)		344,103			140			63,197			39,803
Net cash (used in) / provided by operations		358			(189,930	)		455,035			(40	)		—			265,423
Cash flows from investing activities
Additions to oil and gas properties		—			—			(474,619	)		—			—			(474,619	)
Net adjustments to purchase price of properties acquired		—			—			15,709			—			—			15,709
Proceeds from sales of assets		—			—			448			—			—			448
Acquisition of other property, plant and equipment		—			—			(1,683	)		—			—			(1,683	)
Current period settlements of matured derivative contracts		—			(3,654	)		—			—			—			(3,654	)
Change in restricted cash		—			—			(104	)		—			—			(104	)
Net cash (used in) / provided by investing		—			(3,654	)		(460,249	)		—			—			(463,903	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—			170,000			—			—			—			170,000
Repayment under long-term debt		—			(468,000	)		—			—			—			(468,000	)
Proceeds from senior notes		—			500,000			—			—			—			500,000
Purchases of treasury stock		(358	)		—			—			—			—			(358	)
Payment of debt issuance costs		—			(13,416	)		—			—			—			(13,416	)
Net cash (used in) / provided by financing		(358	)		188,584			—			—			—			188,226
Net increase (decrease) in cash		—			(5,000	)		(5,214	)		(40	)		—			(10,254	)
Cash
Beginning of period		100			6,000			17,650			70			—			23,820
End of period	$	100		$	1,000		$	12,436		$	30		$	—		$	13,566

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2013

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities		2,286			(189,393	)		315,942			733			(3,400	)		126,168
Net cash (used in) / provided by operations		100			(226,440	)		374,647			266			—			148,573
Cash flows from investing activities
Investment in subsidiary		(172,481	)		—			—			—			172,481			—
Additions to oil and gas properties		—			—			(197,618	)		—			—			(197,618	)
Acquisitions of properties		—			—			(178,173	)		—			—			(178,173	)
Proceeds from sales of assets		—			—			963			644			—			1,607
Acquisition of other property, plant and equipment		—			—			(724	)		(910	)		—			(1,634	)
Current period settlements of matured derivative contracts		—			7,586			—			—			—			7,586
Change in restricted cash		—			—			(45	)		—			—			(45	)
Net cash (used in) / provided by investing		(172,481	)		7,586			(375,597	)		(266	)		172,481			(368,277	)
Cash flows from financing activities
Proceeds from investment in JEI		—			172,481			—			—			(172,481	)		—
Proceeds from issuance of long-term debt		—			220,000			—			—			—			220,000
Repayment under long-term debt		—			(172,000	)		—			—			—			(172,000	)
Proceeds from sale of common stock		172,481			—			—			—			—			172,481
Payment of debt issuance costs		—			(683	)		—			—			—			(683	)
Net cash (used in) / provided by financing		172,481			219,798			—			—			(172,481	)		219,798
Net increase (decrease) in cash		100			944			(950	)		—			—			94
Cash
Beginning of period		—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		$	—		$	23,820

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Organization and Description of Business - Organization (Details)		12 Months Ended
	Jul. 29, 2013 Vote class	Dec. 31, 2015 class	Feb. 29, 2016
Organization
Classes of stock, number | class	2	2
JEH | Existing Owners
Organization
The Existing Owners' economic interest in JEH (as a percent)	74.70%	50.60%	50.60%
Class A common stock | Existing Owners
Organization
Ratio in which JEH Units and Class B common stock are exchanged for Class A common stock	1	1
Class B common stock
Organization
Number of votes for each holder of common stock | Vote	1

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Organization and Description of Business - Revision of Previously Issued Financial Statements - Production Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revision of Previously Issued Financial Statements
Net cash provided by operations	$ 69,030	$ 265,423	$ 148,573
Adjustment | Production tax
Revision of Previously Issued Financial Statements
Net cash provided by operations		$ 0

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Organization and Description of Business - Revision of Previously Issued Financial Statements - Exchange of Class B Shares (Details) - shares	Dec. 31, 2015	Dec. 31, 2014
Class A common stock
Revision of Previously Issued Financial Statements
Common Stock, shares outstanding	30,550,907	12,649,658
Class A common stock | Adjustment | Exchange of Class B shares
Revision of Previously Issued Financial Statements
Common Stock, shares outstanding		0
Class B common stock
Revision of Previously Issued Financial Statements
Common Stock, shares outstanding	31,273,130	36,719,499
Class B common stock | Adjustment | Exchange of Class B shares
Revision of Previously Issued Financial Statements
Common Stock, shares outstanding		0

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Organization and Description of Business - Revision of Previously Issued Financial Statements - Consolidated Balance Sheet - Tabular Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Revision of Previously Issued Financial Statements
Accounts Receivable, Oil and gas sales	$ 19,292	$ 51,482
Deferred tax liabilities	22,972	27,474
Additional paid-in-capital	363,723	178,763
Retained earnings	36,569	38,950
Non-controlling interest	$ 536,856	635,945
As Reported
Revision of Previously Issued Financial Statements
Accounts Receivable, Oil and gas sales		49,861
Deferred tax liabilities		27,330
Additional paid-in-capital		177,133
Retained earnings		38,682
Non-controlling interest		636,366
Adjustment | Production tax
Revision of Previously Issued Financial Statements
Accounts Receivable, Oil and gas sales		1,621
Deferred tax liabilities		144
Retained earnings		268
Non-controlling interest		1,209
Adjustment | Exchange of Class B shares
Revision of Previously Issued Financial Statements
Additional paid-in-capital		1,630
Non-controlling interest		$ (1,630)

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Organization and Description of Business - Revision of Previously Issued Financial Statements - Consolidated Statements of Operations (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization and Description of Business
Production and ad valorem taxes	$ 12,130	$ 22,556	$ 15,517
Income tax provision (benefit)	(2,781)	26,218	(71)
Net income (loss)	(9,077)	225,620	22,405
Net income (loss) attributable to non-controlling interests	(6,696)	184,484	24,591
Net income (loss) attributable to controlling interests	$ (2,381)	$ 41,136	$ (2,186)
Earnings (Loss) per share:
Basic earnings (loss) per share (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)
Diluted earnings (loss) per share (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)

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Significant Accounting Policies - Segment Information (Details)	12 Months Ended
	Dec. 31, 2015 segment area
Segment Information
Number of industry segments | segment	1
Number of Geographic Areas in which Entity Operates | area	1

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Significant Accounting Policies - Accounts Receivable (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Accounts Receivable
Payment period of oil and gas sales, minimum	30 days
Payment period of oil and gas sales, maximum	60 days
Period within which joint interest owner obligations becomes due	30 days
Interest charged on past-due balances	$ 0.0

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Significant Accounting Policies - Concentration of Risk (Details) - Credit risk	12 Months Ended
	Dec. 31, 2015 customer Owner	Dec. 31, 2014 customer Owner	Dec. 31, 2013 customer Owner
Accounts receivable - Oil and gas sales
Concentration of Risk
Concentration risk (as a percent)	68.00%	70.00%	79.00%
Number of customers | customer	4	5	8
Accounts receivable - Joint interest owners
Concentration of Risk
Concentration risk (as a percent)	80.00%	67.00%	77.00%
Number of customers | Owner	5	5	5

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Significant Accounting Policies - Dependence on Major Customers (Details) - Oil and gas sales - Customer concentration	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valero Energy Corp.
Dependence on Major Customers
Concentration risk (as a percent)	18.00%	22.00%	13.00%
ETC Field Services LLC
Dependence on Major Customers
Concentration risk (as a percent)	17.00%
NGL Energy Partners LP
Dependence on Major Customers
Concentration risk (as a percent)	15.00%	12.00%
PVR Midstream
Dependence on Major Customers
Concentration risk (as a percent)		12.00%	15.00%
Plains Marketing
Dependence on Major Customers
Concentration risk (as a percent)	16.00%	10.00%	6.00%
Monarch Natural Gas, LLC
Dependence on Major Customers
Concentration risk (as a percent)		10.00%
Unimark LLC
Dependence on Major Customers
Concentration risk (as a percent)	7.00%		13.00%
Mercuria
Dependence on Major Customers
Concentration risk (as a percent)			13.00%

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Significant Accounting Policies - Oil and Gas Properties (Details)	12 Months Ended
	Dec. 31, 2015 ft³ / Boe
Oil and Gas Properties
Minimum project period for capitalization of interest on expenditures	6 months
Unit conversion ratio	6,000

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Significant Accounting Policies - Other Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Minimum
Other Property, Plant and Equipment
Estimated useful lives	3 years
Maximum
Other Property, Plant and Equipment
Estimated useful lives	10 years

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Significant Accounting Policies - Oil and Gas Sales Payable (Details)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies
Period of remittance for oil and gas sales payable	60 days

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Properties, Plant and Equipment - Oil and Gas Properties - Tabular Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Mineral interests in properties
Unproved	$ 75,308	$ 94,526
Proved	1,031,669	1,001,194
Wells and equipment and related facilities	1,289,323	1,094,202
Gross oil and gas properties	2,396,300	2,189,922
Less: Accumulated depletion and impairment	(760,534)	(551,062)
Net oil and gas properties	$ 1,635,766	$ 1,638,860

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Properties, Plant and Equipment - Oil and Gas Properties - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Properties
Costs capitalized in connection with exploratory wells	$ 0.0
Amount of capitalized interest on expenditures	0.0	$ 0.1
Depletion of oil and gas properties	204.2	180.6	$ 113.3
Impairments of proved or unproved oil and gas properties	$ 0.0	$ 0.0	$ 0.0

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Properties, Plant and Equipment - Oil and Gas Properties - Reclassification (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Property [Abstract]
Impairment of oil and gas properties	$ 0	$ 0	$ 0
Exploration	$ 6,551	$ 3,453	16,125
Adjustment | Reclassification for lease abandonment charges
Oil and Gas Property [Abstract]
Impairment of oil and gas properties			(14,400)
Exploration			$ 14,400

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Properties, Plant and Equipment - Other Property, Plant and Equipment - Tabular Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 8,044	$ 7,062
Less: Accumulated depreciation and amortization	(4,171)	(3,014)
Net other property, plant and equipment	3,873	4,048
Leasehold improvements
Other Property, Plant and Equipment
Gross other property, plant and equipment	1,260	1,218
Furniture, fixtures, computers and software
Other Property, Plant and Equipment
Gross other property, plant and equipment	4,090	3,727
Vehicles
Other Property, Plant and Equipment
Gross other property, plant and equipment	1,537	988
Aircraft
Other Property, Plant and Equipment
Gross other property, plant and equipment	910	910
Other
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 247	$ 219

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Properties, Plant and Equipment - Other Property, Plant and Equipment - Depreciation and Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Properties, Plant and Equipment
Depreciation and amortization of other property, plant and equipment	$ 1.3	$ 1.1	$ 0.8

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Acquisition of Properties - Number of Property Acquisitions (Details)	12 Months Ended
	Dec. 31, 2015 entity
Acquisition of Properties
Number of property acquisitions	0

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Acquisition of Properties - Purchase Price (Details) - Sabine acquisition - USD ($) $ in Millions		3 Months Ended
	Dec. 18, 2013	Jun. 30, 2014
Purchase price
Purchase price		$ 179.2
As Reported
Purchase price
Purchase price	$ 193.5

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Acquisition of Properties - Purchase Price Allocation (Details) - Sabine acquisition $ in Thousands	Jun. 30, 2014 USD ($)
Oil and gas properties
Unproved	$ 32,964
Proved	147,024
Asset retirement obligations	(824)
Total purchase price	$ 179,164

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Acquisition of Properties - Pro Forma Results (Details) - Sabine acquisition - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013
Pro Forma
Post acquisition - Total operating revenue	$ 1,365
Post acquisition - Total operating expenses	291
Post acquisition - Operating income	1,074
Post acquisition - Net income	$ 1,074
Pro forma - Total operating revenue		$ 308,773
Pro forma - Total operating expenses		229,648
Pro forma - Operating income		79,125
Pro forma - Net income		$ 45,778

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Long-Term Debt - Tabular Disclosure (Details) - USD ($) $ in Thousands	Feb. 29, 2016	Dec. 31, 2015	Dec. 31, 2014
Senior Unsecured Notes
Total principal amount		$ 860,000	$ 860,000
Less: unamortized discount		(12,088)
Total carrying amount		847,912	860,000
Senior notes
Senior Unsecured Notes
Total principal amount	$ 579,500
2022 Notes | Senior notes
Senior Unsecured Notes
Total principal amount		500,000	500,000
2023 Notes | Senior notes
Senior Unsecured Notes
Total principal amount		250,000
Revolving credit facility | Wells Fargo Bank N.A. | Revolver | Line of credit
Senior Unsecured Notes
Total principal amount		$ 110,000	$ 360,000

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Long-Term Debt - 2022 Notes (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 23, 2015	Feb. 20, 2015
Senior Unsecured Notes
Repayment under long-term debt		$ 335,000	$ 468,000	$ 172,000
2022 Notes | Senior notes
Senior Unsecured Notes
Aggregate principal amount	$ 500,000				$ 500,000	$ 500,000
Stated interest rate (as a percent)	6.75%
Tenders received (as a percent)					100.00%
Wells Fargo Bank N.A. | Revolving credit facility | Revolver | Line of credit
Senior Unsecured Notes
Repayment under long-term debt	$ 308,000
Wells Fargo Bank N.A. | Term loan | Term Loan | Line of credit
Senior Unsecured Notes
Repayment under long-term debt	$ 160,000

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Long-Term Debt - 2023 Notes (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 23, 2015	Dec. 31, 2015	Dec. 31, 2014	Feb. 11, 2016	Jan. 12, 2016	Nov. 18, 2015
Senior Unsecured Notes
Notes proceeds from issuance		$ 236,475	$ 500,000
2023 Notes | Senior notes
Senior Unsecured Notes
Aggregate principal amount	$ 250,000			$ 250,000	$ 250,000
Stated interest rate (as a percent)	9.25%					9.25%
Discount of principal amount (as a percent)	94.59%
Notes proceeds from issuance	$ 236,500

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Long-Term Debt - Other Long-Term Debt (Details) - Wells Fargo Bank N.A. - Line of credit $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 08, 2015 USD ($)	Feb. 23, 2015 USD ($)	Nov. 06, 2014 USD ($)	Nov. 05, 2014 USD ($)	Dec. 31, 2009 agreement
Other Long-Term Debt
Number of credit agreements | agreement								2
Revolving credit facility | Revolver
Other Long-Term Debt
Borrowing base				$ 510.0	$ 562.5	$ 625.0	$ 550.0
Average interest rate (as a percent)	2.39%	2.51%
Average outstanding balance	$ 144.9	$ 333.8
Total interest and commitment fees	$ 5.1	9.5	$ 12.3
Covenant, total leverage ratio	4.00
Covenant, current ratio	1.0
Total leverage ratio	3.2
Current ratio	6.9
Revolving credit facility | London Interbank Offered Rate (LIBOR) | Minimum | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	1.50%
Revolving credit facility | London Interbank Offered Rate (LIBOR) | Maximum | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	2.50%
Revolving credit facility | Federal Funds Effective Swap Rate | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	0.50%
Revolving credit facility | One Month Adjust LIBO Rate | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	1.00%
Revolving credit facility | Base rate | Minimum | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	0.50%
Revolving credit facility | Base rate | Maximum | Revolver
Other Long-Term Debt
Margin interest rate (as a percent)	1.50%
Term loan | Term Loan
Other Long-Term Debt
Total interest and commitment fees		$ 3.6	$ 14.7

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Derivative Instruments and Hedging Activities - Hedging Positions (Details) - Commodity Derivative Instruments	12 Months Ended
	Dec. 31, 2015 bbl / mo MMBTU / mo $ / bbl $ / MMBTU	Dec. 31, 2014 bbl / mo MMBTU / mo $ / bbl $ / MMBTU
Basis swaps | Minimum
Hedging Positions
Contract differential (in dollars per mmbtu) | $ / MMBTU	(0.39)	(0.39)
Nonmonetary notional amount | MMBTU / mo	1,190,000	320,000
Basis swaps | Maximum
Hedging Positions
Contract differential (in dollars per mmbtu) | $ / MMBTU	(0.11)	(0.11)
Nonmonetary notional amount | MMBTU / mo	1,730,000	980,000
Basis swaps | Weighted Average
Hedging Positions
Contract differential (in dollars per mmbtu) | $ / MMBTU	(0.18)	(0.21)
Nonmonetary notional amount | MMBTU / mo	1,360,833	716,667
Oil | Swaps | Minimum
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	54.53	75.05
Nonmonetary notional amount | bbl / mo	54,000	45,000
Oil | Swaps | Maximum
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	100.87	100.95
Nonmonetary notional amount | bbl / mo	194,000	184,054
Oil | Swaps | Weighted Average
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	79.16	84.20
Nonmonetary notional amount | bbl / mo	97,119	113,852
Natural gas | Swaps | Minimum
Hedging Positions
Exercise price (in dollars per mmbtu) | $ / MMBTU	3.22	3.37
Nonmonetary notional amount | MMBTU / mo	700,000	710,000
Natural gas | Swaps | Maximum
Hedging Positions
Exercise price (in dollars per mmbtu) | $ / MMBTU	6.45	6.45
Nonmonetary notional amount | MMBTU / mo	1,640,000	1,772,584
Natural gas | Swaps | Weighted Average
Hedging Positions
Exercise price (in dollars per mmbtu) | $ / MMBTU	4.25	4.40
Nonmonetary notional amount | MMBTU / mo	1,042,857	1,175,275
Natural gas liquids | Swaps | Minimum
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	8.90	8.09
Nonmonetary notional amount | bbl / mo	2,000	2,000
Natural gas liquids | Swaps | Maximum
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	95.24	95.24
Nonmonetary notional amount | bbl / mo	112,000	143,000
Natural gas liquids | Swaps | Weighted Average
Hedging Positions
Exercise price (in dollars per barrels) | $ / bbl	32.62	42.46
Nonmonetary notional amount | bbl / mo	51,792	50,444

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Derivative Instruments and Hedging Activities - Recognized Gain (Loss ) on Derivative Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity Derivative Instruments
Recognized Net Gain (Loss) on Derivative Instruments
Net gains (losses) recognized on derivative instruments	$ 158.8	$ 189.6	$ (2.6)

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Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities - Counterparties (Details)	Dec. 31, 2015 Counterparty
Derivative Instruments and Hedging Activities
Number of counterparties to commodity derivative contracts	6

XML

Derivative Instruments and Hedging Activities - Offsetting Assets (Details) - Commodity Derivative Instruments - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets
Gross Amounts of Recognized Assets	$ 218,036	$ 208,646
Gross Amounts Offset in the Balance Sheet	(527)	(72)
Net Amounts of Assets Presented in the Balance Sheet	217,509	208,574
Net Amount	$ 217,509	$ 208,574

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Derivative Instruments and Hedging Activities - Offsetting Liabilities (Details) - Commodity Derivative Instruments - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Liabilities
Gross Amounts of Recognized Liabilities	$ (538)	$ (100)
Gross Amounts Offset in the Balance Sheet	527	72
Net Amounts of Liabilities Presented in the Balance Sheet	(11)	(28)
Net Amount	$ (11)	$ (28)

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Fair Value Measurement - Financial Instruments Carried at Fair Value by Consolidated Balance Sheet Caption and by Valuation Hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Valuation Hierarchy
Current assets	$ 124,207	$ 121,519
Long-term assets	93,302	87,055
Current liabilities	(11)
Long-term liabilities		(28)
Recurring | Commodity Derivative Instruments
Valuation Hierarchy
Current assets	124,207	121,519
Long-term assets	93,302	87,055
Current liabilities	(11)
Long-term liabilities		(28)
Recurring | Level 2 | Commodity Derivative Instruments
Valuation Hierarchy
Current assets	122,779	120,604
Long-term assets	93,302	85,162
Current liabilities	(11)
Recurring | Level 3 | Commodity Derivative Instruments
Valuation Hierarchy
Current assets	$ 1,428	915
Long-term assets		1,893
Long-term liabilities		$ (28)

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Fair Value Measurement - Quantitative Information about Level 3 Inputs - Assets (Details) - Commodity Derivative Instruments $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) $ / bbl	Dec. 31, 2014 USD ($) $ / bbl
Commodity Derivative Instruments - Assets
Fair Value | $	$ 218,036	$ 208,646
Natural gas liquids | Swaps | Minimum
Commodity Derivative Instruments - Assets
Natural gas liquid futures prices (in dollars per barrel)	8.90	8.09
Natural gas liquids | Swaps | Maximum
Commodity Derivative Instruments - Assets
Natural gas liquid futures prices (in dollars per barrel)	95.24	95.24
Discounted cash flow approach | Level 3 | Natural gas liquids | Swaps
Commodity Derivative Instruments - Assets
Fair Value | $	$ 1,428
Discounted cash flow approach | Level 3 | Natural gas liquids | Swaps | Minimum
Commodity Derivative Instruments - Assets
Natural gas liquid futures prices (in dollars per barrel)	8.90
Discounted cash flow approach | Level 3 | Natural gas liquids | Swaps | Maximum
Commodity Derivative Instruments - Assets
Natural gas liquid futures prices (in dollars per barrel)	47.25

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Fair Value Measurement - Changes in Level 3 Financial Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in fair value of Level 3 instruments
Balance at the beginning of the period	$ 2,780	$ (1,235)
Purchases	648	668
Settlements	(960)	476
Transfers into Level 3		(265)
Transfer to Level 2	(1,367)	332
Changes in fair value	327	2,804
Balance at the end of the period	$ 1,428	$ 2,780

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Fair Value Measurement - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount | 2022 Notes | Senior notes
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	$ 500,000	$ 500,000
Carrying Amount | 2023 Notes | Senior notes
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	250,000
Carrying Amount | Revolving credit facility | Revolver | Line of credit
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	110,000	360,000
Level 3 | Nonrecurring | Fair Value | Revolving credit facility | Revolver | Line of credit
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	110,000	360,000
Level 1 | Nonrecurring | Fair Value | 2022 Notes | Senior notes
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	260,000	$ 384,375
Level 2 | Nonrecurring | Fair Value | 2023 Notes | Senior notes
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Debt	$ 153,283

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Asset Retirement Obligations - Roll Forward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
Balance at beginning of period	$ 13,610	$ 10,963
Liabilities incurred	6,349	1,995	$ 1,516
Accretion of ARO liability	1,087	770	608
Liabilities settled due to sale of related properties	(19)	(109)
Liabilities settled due to plugging and abandonment	(69)	(55)
Change in estimate	22	46
Balance at end of period	$ 20,980	$ 13,610	$ 10,963

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Asset Retirement Obligations - Liability at End of Year (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
ARO liability at end of period	$ 20,980	$ 13,610	$ 10,963
Less: Current portion of ARO	(679)	(3,074)
Total long-term ARO at end of period	$ 20,301	$ 10,536

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Asset Retirement Obligations - Immaterial Errors (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
Liabilities incurred		$ 6,349	$ 1,995	$ 1,516
Accretion of ARO liability		1,087	770	608
Depletion, depreciation and amortization		205,498	$ 181,669	$ 114,136
Immaterial errors originating in 2013 and 2014 | Adjustment
Asset Retirement Obligations
Liabilities incurred		$ 4,700
Accretion of ARO liability	$ 200
Depletion, depreciation and amortization	$ 600

XML

Stock-based Compensation - Management Unit Awards - New Awards (Details)	29 Months Ended
	Dec. 31, 2015 shares
Management Unit Awards
Additional disclosures
Awards (in shares)	0

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Stock-based Compensation - Management Unit Awards - Activity (Details) - Management Unit Awards	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Units
Unvested at the beginning of the period (in shares) | shares	274,385
Granted (in shares) | shares	1,909
Forfeited (in shares) | shares	(1,909)
Vested (in shares) | shares	(85,030)
Unvested at the end of the period (in shares) | shares	189,355
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share) | $ / shares	$ 15.00
Granted (in dollars per share) | $ / shares	15.00
Forfeited (in dollars per share) | $ / shares	15.00
Vested (in dollars per share) | $ / shares	15.00
Unvested at the end of the period (in dollars per share) | $ / shares	$ 15.00

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Stock-based Compensation - Management Unit Awards - Stock Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and administrative expenses | Management Unit Awards
Stock compensation expense
Stock compensation expense	$ 1.3	$ 1.6	$ 10.7

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Stock-based Compensation - Management Unit Awards - Additional Disclosures (Details) - Management Unit Awards $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / shares
Additional disclosures
Weighted average grant date fair value (in dollars per share) | $ / shares	$ 15.00
Unrecognized expenses | $	$ 2.8
Weighted-average remaining recognition period (in years)	1 year 2 months 12 days

XML

Stock-based Compensation - 2013 Omnibus Incentive Plan (Details)	Dec. 31, 2015 shares
2013 Omnibus Incentive Plan | Class A common stock
Stock-based Compensation
Shares reserved (in shares)	3,850,000

XML

Stock-based Compensation - Restricted Stock Unit Awards - Activity (Details) - Restricted Stock Unit Awards - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Awards
Unvested at the beginning of the period (in shares)	324,897
Granted (in shares)	572,939		0
Forfeited (in shares)	(14,995)
Vested (in shares)	(125,596)
Unvested at the end of the period (in shares)	757,245	324,897
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)	$ 17.33
Granted (in dollars per share)	9.58	$ 17.31
Forfeited (in dollars per share)	12.84
Vested (in dollars per share)	16.75
Unvested at the end of the period (in dollars per share)	$ 11.65	$ 17.33

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Stock-based Compensation - Restricted Stock Unit Awards - Stock Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and administrative expenses | Restricted Stock Unit Awards
Stock compensation expense
Stock compensation expense	$ 3.1	$ 1.1	$ 0.0

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Stock-based Compensation - Restricted Stock Unit Awards - Additional Disclosures (Details) - Restricted Stock Unit Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional disclosures
Weighted average grant date fair value (in dollars per share)	$ 9.58	$ 17.31
Awards (in shares)	572,939		0
Unrecognized expenses	$ 5.9
Weighted-average remaining recognition period (in years)	1 year 1 month 6 days

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Stock-based Compensation - Performance Unit Awards - General Information (Details) - Performance Unit Awards	12 Months Ended
	Dec. 31, 2015
Additional disclosures
Vesting term	3 years
Class A common stock
Additional disclosures
Exchangeable ratio of vested performance unit (as a percent)	1.00%
Class A common stock | Minimum
Additional disclosures
Number of shares of common stock issuable upon vesting of the performance unit awards (as a percent)	0.00%
Class A common stock | Maximum
Additional disclosures
Number of shares of common stock issuable upon vesting of the performance unit awards (as a percent)	200.00%

XML

Stock-based Compensation - Performance Unit Awards - Activity (Details) - Performance Unit Awards - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Awards
Unvested at the beginning of the period (in shares)	192,998
Granted (in shares)	361,422		0
Vested (in shares)	(15,232)
Unvested at the end of the period (in shares)	539,188	192,998
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)	$ 21.65
Granted (in dollars per share)	10.27	$ 21.65
Vested (in dollars per share)	14.59
Unvested at the end of the period (in dollars per share)	$ 14.22	$ 21.65

XML

Stock-based Compensation - Performance Unit Awards - Stock Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and administrative expenses | Performance Unit Awards
Stock compensation expense
Stock compensation expense	$ 2.6	$ 0.9	$ 0.0

XML

Stock-based Compensation - Performance Unit Awards - Additional Disclosures (Details) - Performance Unit Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional disclosures
Weighted average grant date fair value (in dollars per share)	$ 10.27	$ 21.65
Awards (in shares)	361,422		0
Unrecognized expenses	$ 4.0
Weighted-average remaining recognition period (in years)	1 year 6 months

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Stock-based Compensation - Performance Unit Awards - Monte Carlo Simulation (Details) - Performance Unit Awards - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Assumptions used to determine the grant date fair value and associated compensation expense
Stock Price (in dollars per share)	$ 10.11	$ 17.07
Beginning Average Stock Price (in dollars per share)	$ 11.56	$ 14.78
Expected Volatility (as a percent)	55.13%	46.95%
Risk-Free Rate of Return (as a percent)	0.79%	0.61%
Number of trading days (in days)	10 days
Remaining in the performance period (in years)	2 years 8 months 1 day	2 years 7 months 13 days
Expected percentage of performance units earned (as a percent)	101.61%	126.80%

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Stock-based Compensation - Restricted Stock Awards - General Information (Details)	12 Months Ended
	Dec. 31, 2015
Restricted Stock Awards
Additional disclosures
Service period from date of grant	1 year

XML

Stock-based Compensation - Restricted Stock Awards - Activity (Details) - Restricted Stock Awards - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Awards
Unvested at the beginning of the period (in shares)	27,430
Granted (in shares)	67,380
Vested (in shares)	(27,430)
Unvested at the end of the period (in shares)	67,380	27,430
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)	$ 18.77
Granted (in dollars per share)	7.30	$ 18.77	$ 15.05
Vested (in dollars per share)	18.77
Unvested at the end of the period (in dollars per share)	$ 7.30	$ 18.77

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Stock-based Compensation - Restricted Stock Awards - Stock Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and administrative expenses | Restricted Stock Awards
Stock compensation expense
Stock compensation expense	$ 0.6	$ 0.4	$ 0.1

XML

Stock-based Compensation - Restricted Stock Awards - Additional Disclosures (Details) - Restricted Stock Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional disclosures
Weighted average grant date fair value (in dollars per share)	$ 7.30	$ 18.77	$ 15.05
Unrecognized expenses	$ 0.2
Weighted-average remaining recognition period (in years)	4 months 24 days

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Stock-based Compensation - Tax Benefit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-based Compensation
Associated tax benefit	$ 1.1	$ 0.4	$ 0.1

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Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Benefit Plans
Expenses	$ 0.5	$ 0.3	$ 0.3

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Income Taxes - Tax Provision - Current and Deferred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current tax expense:
Federal		$ 53	$ 85
State	$ 113
Total current expense	113	53	85
Deferred tax expense (benefit):
Federal	(1,137)	22,140	(1,260)
State	(1,757)	4,025	1,104
Total deferred expense (benefit)	(2,894)	26,165	(156)
Total income tax provision (benefit)	$ (2,781)	$ 26,218	$ (71)

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Income Taxes - Tax Provision - Attributable to Controlling Interests and Non-controlling Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Tax provision
Tax expense (benefit) attributable to controlling interests	$ (1,160)	$ 22,819	$ (1,223)
Tax expense attributable to non-controlling interests	(1,621)	3,399	1,152
Total income tax provision (benefit)	$ (2,781)	$ 26,218	$ (71)

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Income Taxes - Tax Rate (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes
Statutory rate (as a percent)	35.00%	35.00%	35.00%

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Income Taxes - Reconciliation of the Provision for Income Taxes - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$ (11,858)	$ 251,838	$ 22,334
Statutory rate (as a percent)	35.00%	35.00%	35.00%
Income tax expense computed at statutory rate	$ (4,150)	$ 88,144	$ 7,817
Less: Noncontrolling interests	2,911	(65,759)	(9,009)
Income tax expense (benefit) attributable to controlling interests	(1,239)	22,385	(1,192)
State and local income taxes, net of federal benefit	(1,011)	626	(49)
Reduction of TRA liability	(694)
Equity compensation, shortfall	338
Change in enacted rate	(650)
Change in valuation allowance	2,333
Other	(237)	(192)	18
Tax expense (benefit) attributable to controlling interests	(1,160)	22,819	(1,223)
Tax expense attributable to non-controlling interests	(1,621)	3,399	1,152
Total income tax provision (benefit)	$ (2,781)	$ 26,218	$ (71)

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Income Taxes - Reconciliation of the Provision for Income Taxes - Immaterial Error (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Provision calculated at federal statutory income tax rate:
Deferred income tax provision	$ (2,894)	$ 26,165	$ (156)
Immaterial error from the year ended December 31. 2014 | Adjustment
Provision calculated at federal statutory income tax rate:
Deferred income tax provision	$ 900	$ (900)

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Income Taxes - State Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes
Texas state tax rate (as a percent)	0.75%	1.00%
Benefit from revaluing deferred tax assets at the newly enacted rate	$ 1.7
Benefit from revaluing deferred tax assets at the newly enacted rate, non-controlling interest	$ 1.0

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Income Taxes - Deferred Tax Assets and Deferred Tax Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets
Net operating loss	$ 9,414	$ 8,223
Section 754 election tax basis adjustment	47,100	945
Alternative minimum tax credits		53
State deferred tax asset	505	232
Total deferred tax assets	57,019	9,453
Deferred tax liabilities
Investment in consolidated subsidiary JEH	73,559	29,307
Noncurrent state deferred tax liability	4,099	7,449
Total deferred tax liabilities	77,658	36,756
Net deferred tax assets (liabilities)	(20,639)	(27,303)
Valuation allowance	(2,333)
Net deferred tax assets (liabilities)	$ (22,972)	$ (27,303)

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Income Taxes - Net Operating Loss Carry-forward (Details) $ in Millions	Dec. 31, 2015 USD ($)
Operating loss carry-forward
Valuation allowance	$ 2.3
Federal
Operating loss carry-forward
Net operating loss carry-forward	24.8
State
Operating loss carry-forward
Net operating loss carry-forward	$ 19.5

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Income Taxes - Tax Receivable Agreement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes
Tax Savings Receivable in Connection with Tax Receivable Agreement (as a percent)	85.00%
Benefits of cash savings retained under tax receivable agreement (as a percent)	15.00%
Reduction in the liability	$ 2,000
Liability under tax receivable agreement	38,052	$ 803
Valuation allowance	$ 44,800	$ 900

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Income Taxes - Tax Receivable Agreement - Shares Exchanged (Details) shares in Millions	1 Months Ended
	May. 31, 2015 shares
Metalmark | Beneficial owner
Tax Receivable Agreement
Exchange of JEH Units and Class B shares	5

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Earnings per Share - Anti-dilutive Securities (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Awards
Earnings per Share
Antidilutive securities (in shares)	757,245	27,430
Restricted Stock Unit Awards
Earnings per Share
Antidilutive securities (in shares)	67,380	54,656
Performance Unit Awards
Earnings per Share
Antidilutive securities (in shares)	539,188	192,998
Class B common stock
Earnings per Share
Economic interests/rights (as a percent)	0.00%

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Earnings per Share - Basic Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$ (2,381)	$ 41,136	$ (2,186)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic	26,816	12,526	12,500
Weighted-average number of shares of Class A common stock - diluted	26,816	12,535	12,500
Earnings per share:
Basic (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)
Diluted (in dollars per share)	$ (0.09)	$ 3.28	$ (0.17)

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Related Parties - Natural Gas Sale and Purchase Agreement with Monarch Natural Gas, LLC (Details) $ in Thousands		12 Months Ended
	Sep. 01, 2013	Dec. 31, 2015 USD ($) MMBoe	Dec. 31, 2014 USD ($) MMBoe	Dec. 31, 2013 USD ($) MMBoe
Related Party Transactions
Oil and gas sales		$ 194,555	$ 378,401	$ 258,063
Enable Midstream Partners LP
Related Party Transactions
Initial term of the agreement (in years)	10 years
Investee | Monarch Natural Gas, LLC
Related Party Transactions
Production of natural gas and NGLs (in MMBoe) | MMBoe		1.0	1.4	0.8
Oil and gas sales		$ 10,600	$ 37,000	$ 10,400

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Related Parties - Metalmark Capital and Monarch Natural Gas, LLC (Details) $ in Millions		12 Months Ended
	May. 07, 2013	Dec. 31, 2015 director	Dec. 31, 2013 USD ($)
Monarch Natural Gas, LLC | Investee | Metalmark
Related Party Transactions
Metalmark Capital's ownership percentage in Monarch (as a percent)	81.00%
Metalmark | Beneficial owner
Related Party Transactions
Number of directors who are managing directors of the related party | director		2
Annual administration fee | $			$ 0.7
Minimum | Metalmark | Beneficial owner
Related Party Transactions
Metalmark Capital's beneficial ownership interest in the Company (as a percent)		5.00%

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Related Parties - Monarch Natural Gas, LLC Equity Interests (Details) - Monarch Natural Gas, LLC - Investee - USD ($) $ in Millions		12 Months Ended
	May. 07, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transactions
Estimated fair value of equity interests issued to the entity	$ 15.0
Amortization of deferred revenue		$ 2.0	$ 1.2	$ 0.5
Value of equity interests from related party	15.0
Value of equity interests assigned to Jonny Jones	2.4
Value of equity interests reserved for an incentive plan established for certain of the entity's officers	2.6
Value of remaining equity interests distributed to certain of the pre-IPO owners	$ 10.0
Equity interests distributed to management		0.8	0.5
Compensation expense recognized under management distributions and incentive plan		0.5	$ 0.8	$ 0.3
Other assets
Related Party Transactions
Estimated fair value of equity interests issued to the entity		$ 1.3

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Related Parties - Transportation Agreement with Monarch Oil Pipeline LLC (Details) - Monarch Oil Pipeline LLC - Investee $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2015 USD ($) bbl / d MMBoe
Related Party Transactions
Term of Oil Gathering and Transportation Agreement (in years)	10 years
Gathering fees | $		$ 0.4
Oil production transported (in MMBoe) | MMBoe		0.2
Reserved capacity (in barrels per day) | bbl / d		12,000

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Related Parties - Monarch Cash Distribution (Details) $ in Millions	1 Months Ended
	May. 31, 2015 USD ($)
Monarch Natural Gas, LLC | Investee
Related Party Transactions
Cash distributions associated with equity interests	$ 0.7

XML

Commitments and Contingencies - Area Leased (Details)	Dec. 31, 2015 ft²
Office space in Austin, TX
Lease obligations
Leased area of office space in Austin, TX (in square feet)	43,000

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Commitments and Contingencies - Future Minimum Payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Future minimum payments for noncancellable operating leases
2016	$ 945
2017	1,038
2018	1,101
2019	1,122
2020	377
Total	$ 4,583

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Commitments and Contingencies - Rent Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies
Rent expense under operating leases	$ 1.6	$ 0.9	$ 0.8

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Subsequent Events (Details) - USD ($) $ in Thousands	Feb. 29, 2016	Feb. 11, 2016	Jan. 12, 2016	Dec. 31, 2015	Nov. 18, 2015	Mar. 23, 2015	Feb. 23, 2015	Feb. 20, 2015	Dec. 31, 2014	Apr. 01, 2014
Senior Unsecured Notes
Aggregate principal carrying amount				$ 860,000					$ 860,000
Cash
Cash	$ 46,000			21,893					13,566
Senior notes
Senior Unsecured Notes
Aggregate principal amount repurchased	170,500
Aggregate principal carrying amount	579,500
2022 Notes | Senior notes
Senior Unsecured Notes
Stated interest rate (as a percent)										6.75%
Aggregate principal amount						$ 500,000		$ 500,000		$ 500,000
Tenders received (as a percent)						100.00%
Aggregate principal carrying amount				500,000					500,000
2022 Notes | Senior notes | Subsequent event
Senior Unsecured Notes
Aggregate principal amount repurchased	70,500
Purchased amount	27,100
2023 Notes | Senior notes
Senior Unsecured Notes
Stated interest rate (as a percent)					9.25%		9.25%
Aggregate principal amount		$ 250,000	$ 250,000				$ 250,000
Tenders received (as a percent)		100.00%
Aggregate principal carrying amount				250,000
2023 Notes | Senior notes | Subsequent event
Senior Unsecured Notes
Aggregate principal amount repurchased	100,000
Purchased amount	46,500
Wells Fargo Bank N.A. | Revolving credit facility | Revolver | Line of credit
Senior Unsecured Notes
Aggregate principal carrying amount				$ 110,000					$ 360,000
Other Long-Term Debt
Drawn revolver balance	185,000
Undrawn balance	$ 325,000

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Subsidiary Guarantors - Debt Issued (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 subsidiary	Feb. 11, 2016 USD ($)	Jan. 12, 2016 USD ($)	Mar. 23, 2015 USD ($)	Feb. 23, 2015 USD ($)	Feb. 20, 2015 USD ($)	Apr. 01, 2014 USD ($)
Senior notes | 2022 Notes
Subsidiary Guarantors
Issuance of debt				$ 500.0		$ 500.0	$ 500.0
Senior notes | 2023 Notes
Subsidiary Guarantors
Issuance of debt		$ 250.0	$ 250.0		$ 250.0
Issuers | Senior notes | 2022 Notes
Subsidiary Guarantors
Issuance of debt							$ 500.0
Issuers | Senior notes | 2023 Notes
Subsidiary Guarantors
Issuance of debt					$ 250.0
JEH | Guarantor Subsidiaries
Subsidiary Guarantors
Ownership percentage in subsidiary guarantors	100.00%
JEH | Senior notes
Subsidiary Guarantors
Immaterial subsidiaries | subsidiary	2

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Subsidiary Guarantors - General Information (Details)		12 Months Ended
	Jul. 29, 2013 class	Dec. 31, 2015 class	Feb. 29, 2016
Subsidiary Guarantors
Classes of stock, number	2	2
Class A common stock
Subsidiary Guarantors
Economic interests/rights (as a percent)		100.00%
Votes per share entitled to stockholders		1
Class B common stock
Subsidiary Guarantors
Economic interests/rights (as a percent)		0.00%
Votes per share entitled to stockholders		1
Existing Owners | Class A common stock
Subsidiary Guarantors
Ratio in which JEH Units and Class B common stock are exchanged for Class A common stock	1	1
JEH
Subsidiary Guarantors
The Company's economic interest in JEH (as a percent)		49.40%
JEH | Existing Owners
Subsidiary Guarantors
The Existing Owners' economic interest in JEH (as a percent)	74.70%	50.60%	50.60%

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Subsidiary Guarantors - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Feb. 29, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash	$ 46,000	$ 21,893	$ 13,566
Restricted cash		330	149
Accounts receivable, net
Oil and gas sales		19,292	51,482
Joint interest owners		11,314	41,761
Other		15,170	12,512
Commodity derivative assets		124,207	121,519
Other current assets		2,298	3,374
Total current assets		194,504	244,363
Oil and gas properties, net, at cost under the successful efforts method		1,635,766	1,638,860
Other property, plant and equipment, net		3,873	4,048
Commodity derivative assets		93,302	87,055
Other assets		17,967	20,352
Deferred tax assets			171
Total assets		1,945,412	1,994,849
Current liabilities
Trade accounts payable		7,467	136,337
Oil and gas sales payable		32,408	70,469
Accrued liabilities		27,341	19,401
Commodity derivative liabilities		11
Asset retirement obligations		679	3,074
Total current liabilities		67,906	229,281
Long-term debt		847,912	860,000
Deferred revenue		11,417	13,377
Commodity derivative liabilities			28
Asset retirement obligations		20,301	10,536
Liability under tax receivable agreement		38,052	803
Deferred tax liabilities		22,972	27,474
Total liabilities		1,008,560	1,141,499
Stockholders' / members' equity
Treasury stock, at cost; 22,602 shares at December 31, 2015 and December 31, 2014		(358)	(358)
Additional paid-in-capital		363,723	178,763
Retained earnings (deficit)		36,569	38,950
Stockholders' equity		399,996	217,405
Non-controlling interest		536,856	635,945
Total stockholders' equity		936,852	853,350	$ 624,124	$ 428,400
Total liabilities and stockholders' equity		1,945,412	1,994,849
Class A common stock
Stockholders' / members' equity
Common stock		31	13
Class B common stock
Stockholders' / members' equity
Common stock		31	37
Eliminations
Accounts receivable, net
Intercompany receivable		(1,174,863)	(1,208,142)
Total current assets		(1,174,863)	(1,208,142)
Investment in subsidiaries		(444,362)	(233,908)
Total assets		(1,619,225)	(1,442,050)
Current liabilities
Intercompany payable		(1,394,272)	(1,211,958)
Total current liabilities		(1,394,272)	(1,211,958)
Total liabilities		(1,394,272)	(1,211,958)
Stockholders' / members' equity
Members' equity		(761,809)	(866,037)
Non-controlling interest		536,856	635,945
Total stockholders' equity		(224,953)	(230,092)
Total liabilities and stockholders' equity		(1,619,225)	(1,442,050)
JEI (Parent)
Current assets
Cash		100	100
Accounts receivable, net
Other			102
Intercompany receivable		12,866	4,164
Total current assets		12,966	4,366
Deferred tax assets			171
Investment in subsidiaries		444,362	233,908
Total assets		457,328	238,445
Current liabilities
Liability under tax receivable agreement		38,052	803
Deferred tax liabilities		19,280	20,237
Total liabilities		57,332	21,040
Stockholders' / members' equity
Treasury stock, at cost; 22,602 shares at December 31, 2015 and December 31, 2014		(358)	(358)
Additional paid-in-capital		363,723	178,763
Retained earnings (deficit)		36,569	38,950
Stockholders' equity		399,996	217,405
Total stockholders' equity		399,996	217,405
Total liabilities and stockholders' equity		457,328	238,445
JEI (Parent) | Class A common stock
Stockholders' / members' equity
Common stock		31	13
JEI (Parent) | Class B common stock
Stockholders' / members' equity
Common stock		31	37
Issuers
Current assets
Cash		12,448	1,000
Accounts receivable, net
Other		14,444	8,788
Commodity derivative assets		124,207	121,519
Other current assets		444	451
Intercompany receivable		1,161,997	1,203,978
Total current assets		1,313,540	1,335,736
Commodity derivative assets		93,302	87,055
Other assets		17,714	20,098
Total assets		1,424,556	1,442,889
Current liabilities
Trade accounts payable		388	288
Accrued liabilities		15,741	8,914
Commodity derivative liabilities		11
Total current liabilities		16,140	9,202
Long-term debt		847,912	860,000
Deferred revenue		11,417	13,377
Commodity derivative liabilities			28
Deferred tax liabilities		3,692	7,237
Total liabilities		879,161	889,844
Stockholders' / members' equity
Members' equity		545,395	553,045
Total stockholders' equity		545,395	553,045
Total liabilities and stockholders' equity		1,424,556	1,442,889
Guarantor Subsidiaries
Current assets
Cash		9,325	12,436
Restricted cash		330	149
Accounts receivable, net
Oil and gas sales		19,292	51,482
Joint interest owners		11,314	41,761
Other		726	3,622
Other current assets		1,854	2,923
Total current assets		42,841	112,373
Oil and gas properties, net, at cost under the successful efforts method		1,635,766	1,638,860
Other property, plant and equipment, net		3,168	3,252
Other assets		253	254
Total assets		1,682,028	1,754,739
Current liabilities
Trade accounts payable		7,079	136,049
Oil and gas sales payable		32,408	70,469
Accrued liabilities		11,600	10,487
Asset retirement obligations		679	3,074
Intercompany payable		1,391,838	1,209,630
Total current liabilities		1,443,604	1,429,709
Asset retirement obligations		20,301	10,536
Total liabilities		1,463,905	1,440,245
Stockholders' / members' equity
Members' equity		218,123	314,494
Total stockholders' equity		218,123	314,494
Total liabilities and stockholders' equity		1,682,028	1,754,739
Non-Guarantor Subsidiaries
Current assets
Cash		20	30
Accounts receivable, net
Total current assets		20	30
Other property, plant and equipment, net		705	796
Total assets		725	826
Current liabilities
Intercompany payable		2,434	2,328
Total current liabilities		2,434	2,328
Total liabilities		2,434	2,328
Stockholders' / members' equity
Members' equity		(1,709)	(1,502)
Total stockholders' equity		(1,709)	(1,502)
Total liabilities and stockholders' equity		$ 725	$ 826

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Subsidiary Guarantors - Condensed Consolidating Balance Sheet - Additional Information (Details) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Treasury stock
Treasury stock, shares	22,602	22,602
Class A common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	30,573,509	12,672,260
Common Stock, shares outstanding	30,550,907	12,649,658
Class B common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	31,273,130	36,719,499
Common Stock, shares outstanding	31,273,130	36,719,499
JEI (Parent)
Treasury stock
Treasury stock, shares	22,602	22,602
JEI (Parent) | Class A common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	30,573,509	12,672,260
Common Stock, shares outstanding	30,550,907	12,649,658
JEI (Parent) | Class B common stock
Common stock
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares issued	31,273,130	36,719,499
Common Stock, shares outstanding	31,273,130	36,719,499

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Subsidiary Guarantors - Condensed Consolidating Statement of Operations and Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Oil and gas sales	$ 194,555	$ 378,401	$ 258,063
Other revenues	2,844	2,196	1,106
Total operating revenues	197,399	380,597	259,169
Operating costs and expenses
Lease operating	41,027	37,760	25,129
Production and ad valorem taxes	12,130	22,556	15,517
Exploration	6,551	3,453	16,125
Depletion, depreciation and amortization	205,498	181,669	114,136
Accretion of ARO liability	1,087	770	608
General and administrative	33,388	25,763	31,902
Other operating	4,188
Total operating expenses	303,869	271,971	203,417
Operating income (loss)	(106,470)	108,626	55,752
Other income (expense)
Interest expense	(61,289)	(38,805)	(27,409)
Net gain (loss) on commodity derivatives	158,753	189,641	(2,566)
Other income (expense)	(2,852)	(7,624)	(3,443)
Other income (expense), net	94,612	143,212	(33,418)
Income (loss) before income tax	(11,858)	251,838	22,334
Income tax provision (benefit)
Current	113	53	85
Deferred	(2,894)	26,165	(156)
Total income tax provision (benefit)	(2,781)	26,218	(71)
Net income (loss)	(9,077)	225,620	22,405
Net income (loss) attributable to non-controlling interests	(6,696)	184,484	24,591
Net income (loss) attributable to controlling interests	(2,381)	41,136	(2,186)
Eliminations
Other income (expense)
Equity interest in income	4,728	(63,197)	3,400
Income tax provision (benefit)
Net income (loss)	4,728	(63,197)	3,400
Net income (loss) attributable to non-controlling interests	(6,696)	184,484	24,591
JEI (Parent)
Other income (expense)
Other income (expense)	1,984
Other income (expense), net	1,984
Income (loss) before income tax	1,984
Equity interest in income	(4,728)	63,197	(3,400)
Income tax provision (benefit)
Current		53	85
Deferred	(363)	22,008	(1,299)
Total income tax provision (benefit)	(363)	22,061	(1,214)
Net income (loss)	(2,381)	41,136	(2,186)
Net income (loss) attributable to controlling interests	(2,381)	41,136	(2,186)
Issuers
Operating revenues
Other revenues	1,960	1,154	469
Total operating revenues	1,960	1,154	469
Operating costs and expenses
General and administrative	13,565	4,493	4,154
Total operating expenses	13,565	4,493	4,154
Operating income (loss)	(11,605)	(3,339)	(3,685)
Other income (expense)
Interest expense	(59,991)	(37,295)	(26,288)
Net gain (loss) on commodity derivatives	158,753	189,641	(2,566)
Other income (expense)	(4,832)	(7,921)	(3,365)
Other income (expense), net	93,930	144,425	(32,219)
Income (loss) before income tax	82,325	141,086	(35,904)
Income tax provision (benefit)
Current	113
Deferred	(2,531)	4,157	1,143
Total income tax provision (benefit)	(2,418)	4,157	1,143
Net income (loss)	84,743	136,929	(37,047)
Guarantor Subsidiaries
Operating revenues
Oil and gas sales	194,555	378,401	258,063
Other revenues	884	1,042	637
Total operating revenues	195,439	379,443	258,700
Operating costs and expenses
Lease operating	41,027	37,760	25,129
Production and ad valorem taxes	12,130	22,556	15,517
Exploration	6,551	3,453	16,125
Depletion, depreciation and amortization	205,407	181,578	114,046
Accretion of ARO liability	1,087	770	608
General and administrative	19,707	21,181	27,490
Other operating	4,188
Total operating expenses	290,097	267,298	198,915
Operating income (loss)	(94,658)	112,145	59,785
Other income (expense)
Interest expense	(1,298)	(1,510)	(1,121)
Other income (expense)	(4)	297	41
Other income (expense), net	(1,302)	(1,213)	(1,080)
Income (loss) before income tax	(95,960)	110,932	58,705
Income tax provision (benefit)
Net income (loss)	(95,960)	110,932	58,705
Non-Guarantor Subsidiaries
Operating costs and expenses
Depletion, depreciation and amortization	91	91	90
General and administrative	116	89	258
Total operating expenses	207	180	348
Operating income (loss)	(207)	(180)	(348)
Other income (expense)
Other income (expense)			(119)
Other income (expense), net			(119)
Income (loss) before income tax	(207)	(180)	(467)
Income tax provision (benefit)
Net income (loss)	$ (207)	$ (180)	$ (467)

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Subsidiary Guarantors - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income (loss)	$ (9,077)	$ 225,620	$ 22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities	78,107	39,803	126,168
Net cash provided by operations	69,030	265,423	148,573
Cash flows from investing activities
Additions to oil and gas properties	(311,305)	(474,619)	(197,618)
Acquisition of properties			(178,173)
Net adjustments to purchase price of properties acquired		15,709
Proceeds from sales of assets	41	448	1,607
Acquisition of other property, plant and equipment	(1,101)	(1,683)	(1,634)
Current period settlements of matured derivative contracts	144,145	(3,654)	7,586
Change in restricted cash	(181)	(104)	(45)
Net cash used in investing	(168,401)	(463,903)	(368,277)
Cash flows from financing activities
Proceeds from issuance of long-term debt	85,000	170,000	220,000
Repayment under long-term debt	(335,000)	(468,000)	(172,000)
Proceeds from senior notes	236,475	500,000
Purchase of treasury stock		(358)
Payment of debt issuance costs	(1,556)	(13,416)	(683)
Proceeds from sale of common stock	122,779		172,481
Net cash provided by financing	107,698	188,226	219,798
Net increase (decrease) in cash	8,327	(10,254)	94
Cash
Beginning of period	13,566	23,820	23,726
End of period	21,893	13,566	23,820
Eliminations
Cash flows from operating activities
Net income (loss)	4,728	(63,197)	3,400
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(4,728)	63,197	(3,400)
Cash flows from investing activities
Investment in subsidiary			172,481
Net cash used in investing			172,481
Cash flows from financing activities
Proceeds from investment in JEI			(172,481)
Net cash provided by financing			(172,481)
JEI (Parent)
Cash flows from operating activities
Net income (loss)	(2,381)	41,136	(2,186)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(120,398)	(40,778)	2,286
Net cash provided by operations	(122,779)	358	100
Cash flows from investing activities
Investment in subsidiary			(172,481)
Net cash used in investing			(172,481)
Cash flows from financing activities
Purchase of treasury stock		(358)
Proceeds from sale of common stock	122,779		172,481
Net cash provided by financing	122,779	(358)	172,481
Net increase (decrease) in cash			100
Cash
Beginning of period	100	100
End of period	100	100	100
Issuers
Cash flows from operating activities
Net income (loss)	84,743	136,929	(37,047)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(202,359)	(326,859)	(189,393)
Net cash provided by operations	(117,616)	(189,930)	(226,440)
Cash flows from investing activities
Current period settlements of matured derivative contracts	144,145	(3,654)	7,586
Net cash used in investing	144,145	(3,654)	7,586
Cash flows from financing activities
Proceeds from investment in JEI			172,481
Proceeds from issuance of long-term debt	85,000	170,000	220,000
Repayment under long-term debt	(335,000)	(468,000)	(172,000)
Proceeds from senior notes	236,475	500,000
Payment of debt issuance costs	(1,556)	(13,416)	(683)
Net cash provided by financing	(15,081)	188,584	219,798
Net increase (decrease) in cash	11,448	(5,000)	944
Cash
Beginning of period	1,000	6,000	5,056
End of period	12,448	1,000	6,000
Guarantor Subsidiaries
Cash flows from operating activities
Net income (loss)	(95,960)	110,932	58,705
Adjustments to reconcile net income (loss) to net cash provided by operating activities	405,395	344,103	315,942
Net cash provided by operations	309,435	455,035	374,647
Cash flows from investing activities
Additions to oil and gas properties	(311,305)	(474,619)	(197,618)
Acquisition of properties			(178,173)
Net adjustments to purchase price of properties acquired		15,709
Proceeds from sales of assets	41	448	963
Acquisition of other property, plant and equipment	(1,101)	(1,683)	(724)
Change in restricted cash	(181)	(104)	(45)
Net cash used in investing	(312,546)	(460,249)	(375,597)
Cash flows from financing activities
Net increase (decrease) in cash	(3,111)	(5,214)	(950)
Cash
Beginning of period	12,436	17,650	18,600
End of period	9,325	12,436	17,650
Non-Guarantor Subsidiaries
Cash flows from operating activities
Net income (loss)	(207)	(180)	(467)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	197	140	733
Net cash provided by operations	(10)	(40)	266
Cash flows from investing activities
Proceeds from sales of assets			644
Acquisition of other property, plant and equipment			(910)
Net cash used in investing			(266)
Cash flows from financing activities
Net increase (decrease) in cash	(10)	(40)
Cash
Beginning of period	30	70	70
End of period	$ 20	$ 30	$ 70