10-K

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, 2013
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. ý

         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 o Non-accelerated filer ý
(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

         As of June 30, 2013, the last business day of the registrant's most recently completed second fiscal quarter, there was no public market for the registrant's common stock. The registrant's common stock began trading on the New York Stock Exchange on July 24, 2013. The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of December 31, 2013 based on the closing price of the Class A common stock on the New York Stock Exchange on December 31, 2013 of $14.48 per share was $161.7 million.

         There were 12,526,580 and 36,836,333 shares of the registrant's Class A and Class B common stock, respectively, outstanding on March 5, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's definitive proxy statement for the 2014 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.

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. The words "could," "should," "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 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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oil, natural gas and NGLs realized prices;

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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 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 2014 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;

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costs of developing our properties and conducting other operations;

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general economic conditions and the commodity price environment;

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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 liabilities;

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counterparty credit risk;

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governmental regulation and taxation of the oil and natural gas industry;

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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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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 volatility, inflation, lack of availability of drilling 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 ("JEH LLC"). Jones Energy, Inc. ("JONE") is a holding company whose sole material asset is an equity interest in JEH 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 JEH LLC. As the sole managing member of JEH LLC, Jones Energy, Inc. is responsible for all operational, management and administrative decisions relating to JEH LLC's business and consolidates the financial results of JEH LLC and its subsidiaries. Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Jones Energy, Inc.'s initial public offering ("IPO") on July 29, 2013, the pre-IPO owners of JEH LLC converted their existing membership interests in JEH LLC into JEH LLC Units and amended the existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH LLC Units and to admit Jones Energy, Inc. as the sole managing member of JEH LLC.

        Jones Energy, Inc.'s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. Only Class A common stock was offered to investors pursuant to the IPO. The Class B common stock is held by the pre-IPO owners of JEH LLC and can be exchanged (together with a corresponding number of JEH LLC 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. Our Class A common stock has been listed on the New York Stock Exchange ("NYSE") 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 Anadarko and Arkoma basins 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 completions 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 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled over 645 total wells, including over 460 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 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.

        The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil and natural gas basins in the United States, enjoying multiple producing horizons and extensive well control demonstrated over seven decades of development. The formations we target are generally characterized by oil and 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

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production to deliver attractive economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of 2,542 gross identified drilling locations and other opportunities within our existing asset base, and actively pursuing joint venture agreements, farm-out agreements, joint operating agreements and similar partnering agreements, which we refer to as joint development agreements, organic leasing and strategic acquisitions. In all of our joint development agreements, we control the drilling and completion of a well, which is the phase during which we can leverage our operational expertise and cost discipline. Following completion, we in some cases may 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, 2013, our total estimated proved reserves were 89.0 MMBoe, of which 56% were classified as proved developed reserves. Approximately 19% of our total estimated proved reserves as of December 31, 2013 consisted of oil, 37% consisted of NGLs, and 44% consisted of natural gas. As of December 31, 2013, our properties included 835 gross producing wells. For the three years ended December 31, 2013, we drilled 218 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, 2013									Year Ended December 31, 2013
	Estimated Net Proved Reserves					Acreage				Average Daily Net Production
	MMBoe		% Oil and NGLs(1)			Gross Acreage		Net Acreage		MBoe/d		% Oil and NGLs(1)
Anadarko basin:
Cleveland		57.5		62.3	%		152,983		91,376		10.0		66.0	%
Granite Wash		2.4		39.0	%		14,361		6,595		1.1		45.5	%
Arkoma basin:
Woodford		26.2		46.3	%		14,584		3,839		4.0		30.3	%
Other		2.9		24.2	%		36,609		13,266		1.9		34.5	%
All properties		89.0		55.7	%		218,537		115,076		17.0		52.8	%

(1)

Ethane is an NGL and is included in this percentage. Due to declines in ethane pricing and increases in natural gas prices, beginning in December 2012, purchasers of our Woodford production have been electing not to recover ethane from the natural gas stream and instead have been 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 production 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.

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

	As of December 31, 2013
	Producing Wells				Identified Drilling Locations(1)
	Gross		Net		Gross		Net
Anadarko basin:
Cleveland		424		283		667		425
Granite Wash		20		14		33		16
Tonkawa		—		—		209		123
Marmaton		—		—		371		209
Arkoma basin:
Woodford		127		49		811		98
Other		264		69		451		17
All properties		835		415		2,542		888

(1)

Our total identified drilling locations include 366 gross locations associated with proved undeveloped reserves as of December 31, 2013. 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 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled 97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million, $310 million of which we expect will be used to drill and complete wells. The remainder of the 2014 capital expenditure budget is devoted to leasing and other discretionary expenditures. Please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—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 2014 budgeted capital expenditures with our cash flow from operations and projected availability under our senior secured revolving credit facility.

        We currently have ten rigs running in our two core areas, eight in the Cleveland and two in the Woodford. We currently expect to allocate our 2014 capital expenditure budget as follows:

	2014 Capital Expenditure Budget
	(in millions)
Drilling and completion:
Cleveland	$	250
Woodford		50
Other		10
Leasing		20
Other activities		20
All properties and activities	$	350

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Our Business Strategies

        Our goal is to increase value by leveraging the operational expertise of our management and technical teams in our operating areas in order to achieve compelling economic returns and attractive reserve, production and cash flow growth. We seek to achieve this goal by executing the following strategies:

Grow Production and Reserves through Development of Our Multi-Year Inventory.

        We intend to focus on development activities in our operating areas, which we believe to be repeatable, low-risk and low-cost, in order to grow our current level of production and proved reserves. We have extensive experience in the Anadarko and Arkoma basins, having drilled over 645 wells in the area since 1988. We believe our historical drilling experience, together with the results of substantial industry activity within our operating areas, helps reduce the risk and uncertainty associated with drilling horizontal wells in these areas. As of December 31, 2013, we have identified 2,542 gross drilling locations, which we believe will enable us to drill and develop our resource base over many years. We expect 100% of our development capital expenditures in 2014 to be dedicated to horizontal drilling.

Leverage Our Extensive Operational Expertise to Continually Reduce Costs and Enhance Returns.

        Decades of experience in the Midcontinent region 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. For example in the Cleveland, over the past seven years, we have been able to reduce our well spud-to-release time, which directly affects drilling costs, from approximately 30 days to approximately 26 days. We seek to apply this expertise in other projects within our areas of operation to enhance their economic profile.

Execute Strategic Acquisitions, Joint Development Agreements, and Organic Leasing Where Our Operating Experience Can Be Leveraged.

        We have successfully increased our production and reserves through selective acquisitions, targeted joint development agreements and organic leasing, and we intend to continue to evaluate acquisition, partnering and leasing opportunities in and around our areas of operation. We pursue joint development opportunities that complement our acquisition strategy by providing a capital efficient and risk-lowering approach to securing and developing acreage and drilling locations that allows us to apply our expertise in the drilling and completion phase. In this regard, we have established long-term agreements with several large exploration and production companies such as BP, ConocoPhillips, Devon Energy, ExxonMobil, Linn Energy, Vanguard Natural Resources and Samson, in which they have farmed-out portions of their basin operations to us. We have drilled over 279 wells in connection with these types of agreements, over 157 of which have been drilled in connection with an active 13-year drilling relationship with ExxonMobil. 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.

Focus on Exploiting Additional Upside Potential Within Our Portfolio.

        We plan to continue exploiting our proved reserves to maximize production through various enhanced recovery methods, such as optimizing frack design and number of stages. Furthermore, the stacked reservoirs within our asset base provide exposure to additional upside potential in several emerging resource plays. Recently, offset operators have been pursuing the exploration of two newly-identified resource opportunities, the Tonkawa and Marmaton formations in the Anadarko basin. We have begun to assess the potential of these formations within our asset base and believe, based on

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these results, we have approximately 580 potential drilling locations in the Tonkawa and Marmaton formations that provide us with additional resource potential. We plan to start to test the potential of the Tonkawa formation by drilling three pilot wells on our acreage in 2014. 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, Upper, Middle and Lower Morrow formations, and other prospective formations found in the Arkoma basin, including the Hartshorne, Spiro, Wapanuka, Cromwell and Caney Shale formations.

Maintain Operational Control Over Our Drilling and Completion Operations.

        We operated substantially all of the wells that we drilled and completed during 2013, allowing us to effectively manage the timing and levels of our development spending, overall well costs and operating costs. In addition, we expect to operate the drilling and completion phase on approximately 71% of our 2,542 gross identified drilling locations. With over 78% 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.

Opportunistically Allocate Our Resources and Capital to Enhance Returns.

        Our drilling inventory comprises oil, natural gas and NGLs, which enables us to adjust our development approach based on prevailing commodity prices. Currently, we intend to capitalize on the more favorable liquids pricing environment by continuing to drill acreage with significant oil and NGL components, where 100% of our 2014 drilling capital budget is focused. Within our existing portfolio, oil and NGLs account for approximately 56% of our proved reserves as of December 31, 2013. 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 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 over the last 25 years.

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. 100% of our 2014 drilling capital budget is devoted to the Anadarko and Arkoma basins in the U.S. Midcontinent.

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

        Our drilling inventory consists of approximately 2,542 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 a low risk and support a relatively predictable production profile. As of December 31, 2013, we had identified 667 gross drilling locations in the Cleveland play, 811 gross drilling locations in the Arkoma Woodford shale formation and 209 gross locations in the Tonkawa

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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. We have also expanded through joint development agreements with large independent producers and major oil and gas companies in the Cleveland and Woodford formations. In 2013, we drilled 97 gross wells, as compared to 48 gross wells drilled in 2012, representing a 102% increase. Furthermore, we have identified additional locations in several emerging resource plays that we intend to explore and develop in the coming years, including 33 gross locations in the Granite Wash formation, 209 gross locations in the Tonkawa formation and 371 gross locations in the Marmaton formation.

Extensive Operational Expertise and Low-Cost Operating Structure.

        Drilling horizontal wells has been our primary drilling approach for the last nine years. Having drilled over 460 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 service providers, vendors and crews, 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 intend to actively hedge our future production in order to reduce the impact of commodity price volatility on our cash flows. Each quarter, we typically review the production results from recently drilled wells and begin entering into commodity price hedges of up to 100% of expected production from those wells in order to secure our rates of return for up to five years. As of December 31, 2013, we had over $680 million of notional value in existing hedges with the lenders under our credit facilities.

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

        The top four executives of our management team average more than 25 years of industry experience. Furthermore, our management team averages over 20 years of industry experience and has 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 major and large independent oil and natural gas companies, including ExxonMobil, BP, Southwestern Energy, Samson, Marathon and Standard Oil.

Alignment of Management Team.

        Our predecessor 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 currently control approximately 28% of our combined voting power and economic

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interest. We believe the equity interests of our officers and directors align their interests and provide substantial incentive to grow the value of our business.

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.

        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 67% of our estimated proved reserves as of December 31, 2013 and approximately 66% of our average daily net production for the year ended December 31, 2013 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.

        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 73 gross (56 net) wells as operator in the Anadarko basin in 2013. Our operations in the Anadarko basin are primarily focused on the Cleveland formation where we have 424 producing wells. We also have acreage in the Granite Wash, Tonkawa, Marmaton, Atoka shale and Cherokee shale formations located in the eastern portion of the Texas Panhandle and western Oklahoma. We intend to explore and develop the Tonkawa formation beginning in 2014, and believe that the Marmaton, Atoka shale and Cherokee shale formations provide longer-term potential in the Anadarko basin.

        On December 18, 2013, we acquired from Sabine Mid-Continent, LLC certain producing and undeveloped oil and gas assets in the Anadarko basin located in the Texas Panhandle and western Oklahoma for approximately $193.5 million, subject to customary closing adjustments. The acquired Sabine properties produced approximately 2,227 boe/day in the 14 day period in 2013 during which we owned the properties.

        Producing Formations.    Our production in the Anadarko basin is currently derived primarily from the following formations, where we have 444 gross (297 net) producing wells and where we have identified 700 gross (441 net) drilling locations as of December 31, 2013, of which 238 have proved undeveloped reserves attributed to them as of December 31, 2013. 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 located in Ochiltree, Lipscomb 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, 2013, we operated 322 gross (244 net) producing wells with working interests ranging from approximately 25% to 100% for our leasehold in the Cleveland formation. Our Cleveland properties contained 57.5 MMBoe of estimated net proved reserves as of

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December 31, 2013, 62% of which are oil and NGLs, and generated an average daily net production of 10.9 MBoe/d for the month ended December 31, 2013. We have identified 667 gross (425 net) drilling locations in the Cleveland formation as of December 31, 2013. Of these 667 locations, 523 locations (78%) are attributable to acreage that is currently held by production and 232 locations (35%) are attributable to proved undeveloped reserves as of December 31, 2013. We are currently running 8 rigs in the Cleveland formation and plan to spend approximately $250 million drilling and completing wells there in 2014, representing approximately 81% of our drilling and completion budget.

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Granite Wash Formation.  Our Granite Wash acreage is 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 tight, complex, quartz rich alluvial liquids-rich wash.

As of December 31, 2013, we operated 19 gross (13 net) producing wells in this formation with an average working interest of 75%. Our Granite Wash properties contained 2.4 MMBoe of estimated net proved reserves as of December 31, 2013, approximately 39% of which are oil and NGLs. We have not allocated any capital expenditures to the Granite Wash formation in our 2014 drilling budget. We have 33 gross (16 net) remaining drilling locations in the Granite Wash formation as of December 31, 2013.

        Additional Targeted Formations.    We also own properties in the following formations of the Anadarko basin, where we have identified 580 gross (332 net) drilling locations as of December 31, 2013, none of which have proved reserves attributed to them. See "Drilling Locations" for more information regarding the processes and criteria through which these drilling locations were identified.

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Tonkawa Formation.  As of December 31, 2013, we have identified 209 gross (123 net) drilling locations in the Tonkawa formation in Lipscomb and Hemphill counties in Texas. In addition, we have other properties in the Tonkawa formation located 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 sandstone, ranging in thickness from 20 feet to 40 feet. We drilled our first horizontal Tonkawa well in May of 2010 and drilled two additional horizontal wells in the formation under a farm-out with Samson that is not part of our current leasehold. Beginning in the second quarter of 2014, we plan to drill three additional test wells in different areas of the Company's leasehold acreage in the Tonkawa formation.

•

Marmaton Formation.  As of December 31, 2013, we have identified 371 gross (209 net) drilling locations in the Marmaton formation. Our properties in the Marmaton formation are all undeveloped and span three sub-formations: properties located in Ellis County, Oklahoma characterized by fluvio-deltaic sands, properties located in Northeast Ochiltree and Northwest Lipscomb counties, Texas characterized by shallow marine sands, and properties located 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. We have not allocated any capital expenditures to the Marmaton formation in our 2014 drilling budget.

        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, Upper, Middle and Lower Morrow formations. As of December 31, 2013, the acreage associated with these opportunities is approximately 82% held by production. The Atoka and Cherokee formations, in particular, have attractive geologic properties, and we may elect to pursue their development in the future.

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Arkoma Basin

        Approximately 29% of our estimated proved reserves as of December 31, 2013, and approximately 19% of our average daily net production for December 2013, 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 from multiple horizons, which range in depth from 500 to 21,000 feet.

        As of December 31, 2013, we operated approximately 66% of our properties in the Arkoma basin and produce primarily from the Woodford formation. Our current leasehold position also provides longer term potential exposure to other prospective formations in the Arkoma basin, including the Hartshorne, Spiro, Wapanuka, Cromwell and Caney formations.

•

Woodford Shale Formation.  Our properties in the Woodford shale formation are located 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, 2013, we operated 84 gross (44 net) producing wells in the formation with an average working interest of 52%. Our Woodford shale formation properties contained 26.2 MMBoe of estimated net proved reserves as of December 31, 2013, 46% of which are NGLs, and generated an average daily net production of 3.3 MBoe/d for the month ended December 31, 2013. We drilled 13 gross (4 net) additional wells in the Woodford shale formation in 2013. We have identified 811 gross (98 net) drilling locations in the Woodford shale formation as of December 31, 2013, of which 13% have proved undeveloped reserves attributed to them as of December 31, 2013. We plan to spend approximately $50 million drilling and completing wells there in 2014, representing approximately 16% of our budgeted 2014 drilling capital expenditures.

Drilling Locations

        We have identified a total of 2,542 gross (888 net) drilling locations, all of which are horizontal drilling locations. Of these 2,542 locations, 2,033 locations are attributable to acreage that is currently held by production and approximately 366 (14%) are attributable to proved undeveloped reserves as of December 31, 2013. In order to identify drilling locations, we apply geologic screening criteria based on the presence of a minimum threshold of gross pay sand 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 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 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

12

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."

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, 2013, 2012 and 2011, which are based upon reserve reports of Cawley, Gillespie & Associates, Inc., or Cawley Gillespie, our independent reserve engineers. 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. The summary data with respect to our estimated net proved oil and natural gas reserves as of December 31, 2013 include the reserves attributable to the properties acquired in the Sabine acquisition.

	As of December 31,
	2013		2012		2011
Reserve Data:
Estimated proved reserves:
Oil (MBbls)		16,688		12,540		7,440
Natural gas (MMcf)		236,648		228,080		244,579
NGLs (MBbls)		32,915		34,746		34,606
Total estimated proved reserves (MBoe)(1)		89,045		85,299		82,809
Estimated proved developed reserves:
Oil (MBbls)		7,129		4,261		2,535
Natural gas (MMcf)		139,622		110,956		110,434
NGLs (MBbls)		19,101		16,320		14,021
Total estimated proved developed reserves (MBoe)(1)		49,501		39,074		34,961
Estimated proved undeveloped reserves:
Oil (MBbls)		9,559		8,278		4,905
Natural gas (MMcf)		97,025		117,124		134,146
NGLs (MBbls)		13,814		18,426		20,586
Total estimated proved undeveloped reserves (MBoe)(1)		39,544		46,225		47,849
PV-10 (in millions)(2)	$	1,017	$	782	$	916
Standardized measure (in millions)(3)		941		782		916

(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

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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. Prior to the reorganization that occurred in 2013 in connection with the IPO of shares of its Class A common stock, the predecessor of Jones Energy, Inc. was a limited liability company that was not subject to entity-level taxation during the periods presented except for the Texas franchise tax. Accordingly, standardized measure for historical periods was not reduced for income taxes. However, upon consummation of the IPO, Jones Energy, Inc. became subject to entity-level taxation, which is reflected in the standardized measure as of December 31, 2013.

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

	As of December 31,
	2013		2012		2011
Oil, Natural Gas and NGLs Benchmark Prices:
Oil (per Bbl)(1)	$	96.78	$	94.71	$	96.19
Natural gas (per MMBtu)(2)		3.67		2.76		4.12
NGLs (per Bbl)(3)		28.33		31.27		47.26

(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, 2013, 2012 and 2011, the average realized prices for oil were $91.74, $90.74 and $92.04 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, 2013, 2012 and 2011, the average realized prices for natural gas were $3.13, $2.24 and $3.83 per MMBtu, respectively.

(3)

Prices for NGLs in the table above reflect the average realized prices for the prior 12 months. 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.

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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, 2013, 2012 and 2011.

	As of December 31,
	2013		2012		2011
	(in millions)
PV-10	$	1,017	$	782	$	916
Present value of future income taxes discounted at 10%		76		—		—
Standardized measure	$	941	$	782	$	916

        Prior to the IPO, the Company was not subject to federal income tax; hence no income taxes were applied to reserve values in the previous years.

Internal Controls

        Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by our corporate reservoir engineering staff, all of whom are independent from our operating teams. 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 anticipate that the audit committee of our board of directors will conduct a similar review on an 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

15

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 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 completion using similar techniques.

Qualifications of Responsible Technical Persons

        Internal engineer.    Eric Niccum, our Executive Vice President and Chief Operating Officer, is the technical person 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 20 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 23 years of experience in reserves evaluation and joined Cawley Gillespie as a reserve engineer in 1992. He has a Bachelors 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).

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Development of Proved Undeveloped Reserves

        As of December 31, 2013, none of our proved undeveloped reserves at December 31, 2013 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 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 can 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, if needed, borrowings under our senior secured revolving credit facility. 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."

        Our proved undeveloped reserves have decreased from 46.2 MMBoe at December 31, 2012 to 39.5 MMBoe at December 31, 2013 due to (i) the conversion of 5.1 MMBoe of proved undeveloped reserves to proved developed reserves; (ii) net negative revisions of 18.1 MMBoe, primarily due to the expiration of the Company's JDA with Southridge (15.5 MMBoe) and production performance in the Cleveland (3.5 MMBoe); (iii) additions of 8.9 MMBoe from extensions and discoveries; and (iv) additions of 7.6 MMBoe for purchases of minerals in place. Proved undeveloped reserves declined as a percentage of total reserves from 54% for the year ending December 31, 2012 to 44% for the year ending December 31, 2013. For the year ended December 31, 2013, we converted 5.1 MMBoe of proved undeveloped reserves to proved developed reserves or 11% of total proved undeveloped reserves booked at December 31, 2012. We incurred approximately $104 million in capital to convert proved undeveloped reserves to proved developed reserves during the year ended December 31, 2013. Our 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled 97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million, $310 million of which we expect to use to drill and complete wells. Costs of proved undeveloped reserve development in 2013 do not represent the total costs of these conversions, as additional costs may have been recorded in previous years. Estimated future development costs relating to the development of 2013 year-end proved undeveloped reserves is $533 million.

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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,
	2013		2012		2011
Production and Operating Data:
Net Production Volumes(1):
Oil (MBbls)		1,557		746		811
Natural gas (MMcf)		17,575		14,066		11,443
NGLs (MBbls)		1,724		1,773		1,215
Total (MBoe)		6,210		4,863		3,933
Average net production (Boe/d)		17,014		13,287		10,775
Average Sales Price(2):
Oil (per Bbl)	$	93.22	$	89.71	$	90.96
Natural gas (per Mcf)		3.16		2.17		3.49
NGLs (per Bbl)		33.30		29.07		44.04
Combined (per Boe) realized		41.56		30.63		42.53
Average Unit Costs per Boe:
Lease operating expense	$	4.47	$	4.75	$	5.48
Production tax expense		2.07		1.15		1.36
Depreciation, depletion and amortization		18.38		16.60		17.52
General and administrative expense(3)		5.14		3.26		4.24

(1)

The Lipscomb SE field constituted approximately 26% of our estimated proved reserves as of December 31, 2013. Our production from the Lipscomb SE field was 1,751 MBoe and 36 MBoe for the years ended December 31, 2013 and 2012, respectively. The 2013 production was comprised of 858 MBbls of oil, 2,786 MMcf of natural gas and 430 MBbls of NGLs. The 2012 production was comprised of 17 MBbls of oil, 61 MMcf of natural gas and 9 MBbls of NGLs. The Lipscomb SE field was acquired in December 2012, therefore we had no production from the field for the year ended December 31, 2011.

The Coalgate Woodford field constituted approximately 19% of our estimated proved reserves as of December 31, 2013. Our production from the Coalgate Woodford field was 1,158 MBoe, 1,529 MBoe, and 675 MBoe for the years ended December 31, 2013, 2012 and 2011, respectively. The 2013 production was comprised of 19 MBbls of oil, 4,766 MMcf of natural gas and 345 MBbls of NGLs. The 2012 production was comprised of 33 MBbls of oil, 4,357 MMcf of natural gas and 770 MBbls of NGLs. The 2011 production was comprised of 10 MBbls of oil, 2,029 MMcf of natural gas and 327 MBbls NGLs.

(2)

Prices do not include the effects of derivative cash settlements.

(3)

General and administrative includes non-cash stock-based compensation of $13.6 million, $0.6 million and $1.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Excluding stock-based compensation from the above metric results in average general and administrative cost per Boe of $2.95, $3.15 and $3.95 for the years ended December 31, 2013, 2012 and 2011, 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,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		97		61		44		22		71		34
Mechanical failure		—		—		2		1		—		—
Dry		—		—		—		—		—		—
Exploratory Wells:
Productive		—		—		—		—		—		—
Dry		—		—		2		1		2		1
Total Wells:
Productive		97		61		44		22		71		34
Mechanical failure		—		—		2		1		—		—
Dry		—		—		2		1		2		1
Total		97		61		48		24		73		34

        For the three years ended December 31, 2013, we had no developmental wells that were deemed dry wells and 4 gross (2 net) exploratory wells deemed dry wells. In this same period, we experienced a total of 2 mechanical failures that were not reservoir related. As of December 31, 2013, there were 32 gross (20 net) development wells in the process of drilling or completion. For the three years ended December 31, 2013, we drilled 191 gross (115 net) wells as operator with over a 99% success rate.

        From January 1, 2013 through December 31, 2013, we successfully drilled 38 gross proved undeveloped wells and completed 29 gross proved undeveloped wells.

Productive Wells

        The following table sets forth our total gross and net productive wells by oil or natural gas completion as of December 31, 2013.

	Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Operated(1)		175		137		312		233		487		370
Non-operated		57		14		291		31		348		45
Total		232		151		603		264		835		415

(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.

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, 2013 for each of our producing areas.

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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, 2013, over 78% of our leasehold acreage was held by existing production.

	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
Cleveland		119,007		73,408		33,976		17,968		152,983		91,376
Woodford(1)		8,889		2,533		5,695		1,306		14,584		3,839
Granite Wash		14,361		6,595		—		—		14,361		6,595
Other		21,610		7,534		14,999		5,732		36,609		13,266
All properties(2)		163,867		90,070		54,670		25,006		218,537		115,076

(1)

Excludes gross and net acreage associated with the joint development agreements with Vanguard. Acreage associated with the Vanguard joint development agreement is assigned to us at the time the first well in each unit is pooled and/or drilled.

(2)

Includes proved undeveloped reserves associated with joint development agreements with third parties. 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. Please see "Risk Factors—If we do not fulfill our obligation to drill the minimum number 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."

Undeveloped acreage expirations

        The following table sets forth the number of gross and net undeveloped acres as of December 31, 2013 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 2014				Expiring 2015				Expiring 2016
	Gross		Net		Gross		Net		Gross		Net
Cleveland		6,048		2,766		5,545		4,232		3,585		2,442
Woodford		2,517		299		3,506		662		566		164
Granite Wash		—		—		—		—		—		—
Other		142		27		—		—		854		437
All properties		8,707		3,092		9,051		4,894		5,005		3,043

        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 production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of 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, 2013 attributed to acreage whose lease expiration date precedes the

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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 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. In recent years, the United States onshore oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have 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 shortages 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.

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 20% to 25%. Our net revenue interests average 57% for our operated leases and 35% including all operated and non-operated leases.

        Over 78% 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.

        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

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pipeline indices less any associated fees. For approximately 98% 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.

        Recently, changes in NGL prices have altered market conditions. Due primarily to the large supply of ethane on the market, the price of ethane has 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, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% 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 or hot summers 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 significant 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 drill-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.

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        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, 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;

•

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.

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        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 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 has 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, a term broadly defined. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by 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 has announced its intention to propose regulations by 2014 under the Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities.

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

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opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals 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 EPA is the permitting authority and released permitting guidance on the use of diesel fuel as an additive in hydraulic fracturing fluids in February 2014. 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, at the direction of the President, 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 November 23, 2011, the EPA announced that it was granting in part a petition to initiate rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and gas exploration and production. Also, BLM is considering proposed rules regarding well stimulation, chemical disclosures, and other requirements for hydraulic fracturing on federal and Indian lands. BLM released a proposed rule requiring the disclosure of chemicals used during hydraulic fracturing and addressing drilling plans, water management, and wastewater disposal on federal and Indian lands in May 2012. However, BLM pulled back its proposal in January 2013 after reviewing comments and published an updated proposed rule on May 24, 2013. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil 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 Louisiana and Oklahoma, have adopted similar chemical disclosure measures. 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 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

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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. EPA issued a final rule revising certain aspects of the rules on August 5, 2013 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. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for methane emissions from the oil and gas sector, which was not addressed in the EPA rules that became effective on October 15, 2012. The notice of intent also requested the EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. 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.

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, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar

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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 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 become subject to operating restrictions or bans or limit future development activity in the affected areas. For example, the U.S. Fish and Wildlife Service proposed on December 11, 2012, to list the Lesser Prairie Chicken as a threatened species under the Endangered Species Act. The period for the public to submit comments on this proposal initially was set to expire on March 11, 2013 but, in response to requests submitted by federal congressmen, the Fish and Wildlife Service reopened the comment period on May 6, 2013. A final decision regarding whether to finalize the proposal is expected by March 30, 2014. The listing of the Lesser Prairie Chicken, or any other species in areas that we operate, could force us to incur additional costs and delay or otherwise limit our operations.

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 exploration and production activities, as well as proposed exploration and development plans, 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 has begun to regulate 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. In June 2010, the EPA adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which sets regulatory emissions thresholds for stationary sources of GHGs under the Prevention of Significant Deterioration (PSD) and Title V programs. PSD permitting has been applicable to new and modified stationary sources that emit GHGs above statutory and regulatory thresholds since January 2, 2011. The EPA has announced its intent to consider lowering the Tailoring Rule regulatory thresholds, which would likely subject additional stationary sources to GHG permitting requirements under the PSD and Title V programs. 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.

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        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. Reporting was first required in 2012 for emissions occurring in 2011. Our operations are not currently subject to this program, but there is no guarantee that the EPA will not expand the program to additional sources and facilities. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs.

        The EPA has also proposed the first New Source Performance Standards (NSPS) for GHG emissions. The proposed GHG NSPS applies to carbon dioxide emissions from certain electric utility generating units. This proposed NSPS does not regulate our operations, but if EPA were to promulgate a GHG NSPS applicable to our operations we could incur significant costs to control our emissions and comply with regulatory 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 federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. 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.

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 the implementing 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 the 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 or pollution control activities for the years ended December 31, 2013 or 2012. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2014 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 our business activities, financial condition or results of operations.

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Offices

        We currently lease approximately 31,000 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 2017. We also lease field offices in Canadian, Texas and McAlester, Oklahoma.

Employees

        As of December 31, 2013, we had 91 employees, including 31 technical (geosciences, engineering, land), 22 field operations, 29 corporate (finance, accounting, planning, business development, IT, office management) and 9 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.

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. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling

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commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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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;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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fires and blowouts;

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

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declines in oil, natural gas and NGL prices;

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limited availability of financing at acceptable rates;

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title problems; and

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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:

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landing our wellbore in the desired drilling zone;

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

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running our casing the entire length of the wellbore; and

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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:

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the ability to fracture stimulate the planned number of stages;

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

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

        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

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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 2013 were $240 million and our budgeted capital expenditures for 2014 are $350 million. Historically, we have funded development and operating activities primarily through a combination of equity capital raised from a private equity partner and our initial public offering, through borrowings under our bank credit facilities 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 credit facilities and the issuance of debt and equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

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

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

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the prices at which we sell our production;

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

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take-away capacity;

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our ability to acquire, locate and produce new reserves;

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

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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 our second lien term loan facility 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.

        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 our second lien term loan facility 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 44% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2013. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, declines in commodity prices could cause us to reevaluate our development plans and delay or cancel development. Delays in the development of

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our reserves or increases in costs to drill and develop such reserves 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 could cause us to have to reclassify our proved reserves as unproved reserves.

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 will likely continue to be volatile in the future. 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:

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

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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;

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

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

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

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localized supply and demand fundamentals and transportation availability;

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weather conditions and natural disasters;

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domestic, local and foreign governmental regulations and taxes;

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

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trading prices of futures contracts;

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

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technological advances affecting energy consumption;

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the price and availability of alternative fuels; and

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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 28% of our 2013 production, and we realized an average price of $33.30 per barrel. 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 deteriorate, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, may be reduced, 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

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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 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.

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 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.

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 from 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. In addition, unless 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.

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If commodity prices decrease, we may be required to take 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 also result in 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.

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, 2013. 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.

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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 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:

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

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actual cost of development and production expenditures;

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the amount and timing of actual development and production; and

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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. Prior to the consummation of the IPO, as a limited liability company, we generally were not historically subject to entity-level taxation. Accordingly, our standardized measure for historical periods does not provide for federal or state corporate income taxes because taxable income was passed through to our equity holders. However, upon consummation of the IPO, we became subject to entity-level taxation for federal income tax purposes, and our future income taxes will be dependent upon our future taxable income.

        If oil prices decline by $10.00 per Bbl, then our standardized measure as of December 31, 2013 excluding hedging impacts would decrease approximately $120.0 million. If natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2013 excluding hedging impacts would decrease by approximately $108.4 million.

Over 97% 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 97% of our estimated proved reserves as of December 31, 2013 were located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, approximately 65% of which are being produced from the Cleveland formation from properties 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.

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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, 2013 purchases by our top four customers accounted for approximately 15%, 13%, 13% and 13%, 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.

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 and our second lien term loan facility impose certain limitations on our ability to enter into mergers or combination transactions. Our senior secured revolving credit facility and our second lien term loan facility also limit 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:

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

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an inability to successfully integrate the assets we acquire;

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

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

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

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

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

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

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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, including the Sabine 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

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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.

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 drill-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.

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 NGLs 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

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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 and our second lien term loan facility limit 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, 2014, 2015, 2016 and 2017, approximately 38%, 59%, 69% and 73%, respectively, of our estimated total oil, natural gas and NGL production, based on our reserve report as of December 31, 2013, 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. It is also possible that a larger percentage of our future production will not be hedged as compared with past years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

        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 intended. 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. 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.

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The adoption of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate 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, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although 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 over-the-counter derivatives. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

        In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC's original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. Since that time, the CFTC has reproposed the rule in substantially the same form as the rule that was vacated by the court, but with certain non-substantive changes in response to the court's decision. The CFTC has sought comment on the position limits rule as reproposed, but has yet to issue its final rule. The CFTC also has withdrawn its appeal of the court order vacating the original position limits rule.

        If these or similar position limits go into effect in the future, the timing of implementation of the final rules, their applicability to, and impact on, us and the ultimate success of any legal challenge to their validity remain uncertain, and they could have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives.

        The Dodd-Frank Act also imposes a number of other new requirements on certain over-the-counter derivatives and subjects certain swap dealers and major swap participants to significant new regulatory requirements, which in certain cases may cause them to conduct their activities through new entities that may not be as creditworthy as our current counterparties, all of which may have a material adverse effect on us. The impact of this regulatory regime on the availability, pricing and terms and conditions of commodity derivatives remains uncertain, but the final requirements could have a materially adverse effect on our ability to hedge our exposure to commodity prices.

        If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil, natural gas and NGLs. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated 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

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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; 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.

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

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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 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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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.

        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

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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 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, 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

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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."

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 recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, in states where 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, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate 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

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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. In the event 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 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 expects to release a final draft report for public comment and peer review in 2014. Moreover, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and plans to propose pretreatment standards this year. 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. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil 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, the U.S. Department of the Interior's Bureau of Land Management, or BLM, is considering rules regarding well stimulation, chemical disclosures and other requirements for hydraulic fracturing on federal and Indian lands. BLM released a proposed rule requiring the disclosure of chemicals used during hydraulic fracturing and addressing drilling plans, water management and wastewater disposal, on federal and Indian lands in May 2012. However, BLM pulled back its proposal in January 2013 after reviewing comments and published an updated proposed rule on May 24, 2013.

        Further, on April 17, 2012, the EPA released final rules to subject all 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 will be 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. EPA issued a final rule revising certain aspects of the rules on August 5, 2013. Depending on the outcome of such

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judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA may issue new rules. We are currently evaluating the effect these rules will have on our business. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for methane emissions from the oil and gas sector, which was not addressed in the EPA rules that became effective on October 15, 2012. The notice of intent also requested the EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. 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.

        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 has begun adopting and implementing 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. Since January 2, 2011, the EPA has required new or modified stationary sources that emit GHGs at levels above regulatory and statutory thresholds to apply for a Prevention of Significant Deterioration, or PSD, permit under the Clean Air Act. The EPA set the current regulatory thresholds in its "Tailoring Rule," which was intended to avoid the need for large numbers of relatively small GHG-emitting sources to obtain a permit under the Clean Air Act. The EPA has also indicated that it may revise its Tailoring Rule carbon dioxide equivalent thresholds downward in a future rulemaking, which would likely subject additional stationary sources to GHG permitting requirements.

        The EPA has also proposed GHG New Source Performance Standards under the Clean Air Act for certain electric utility generating units and may propose GHG NSPS for additional source categories in the future. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission 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 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. Consequently,

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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 gas production operations. Productive zones frequently contain water that must be removed in order for the 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 gas in commercial quantities. The produced water currently is transported from the lease and injected into disposal wells. 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 expects to issue new standards regarding the disposal of wastewater from hydraulic fracturing into publicly owned treatment facilities this year. 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.

Increases in interest rates could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms of 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, 2013, we had approximately $77 million of total available borrowing capacity 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 $575 million available under our credit facilities would result in increased annual interest expense of approximately $6.0 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.

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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 and Vanguard Natural Resources. 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.

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, 2013, the Jones family and Metalmark Capital held approximately 74.7% 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. 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.

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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.

        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 included certain errors in our annual financial statements for the years ended 2010, 2011 and 2012, including out-of-period adjustments and errors in the calculation of our depreciation, depletion and amortization expense and our asset retirement obligations. We and our independent registered public accounting firm concluded that these control deficiencies 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. The control deficiencies described above, at varying degrees of severity, contributed to the material weakness in the control environment as further described below.

        In 2010 and 2011, we did not maintain effective controls to ensure that correct inputs and formulas in spreadsheets were used in our calculation of depreciation, depletion and amortization, or DD&A, expense. In 2012, the lack of effective controls over last-minute journal entries and use of final adjusted production data resulted in the misstatement of DD&A. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2010, 2011, and 2012.

        In December 2012, we were notified by the Oklahoma Tax Commission that sales tax had not been remitted on tangible property conveyed as part of the sale of a number of oil and gas properties. Consequently, tax expense for periods prior to 2012 was understated. In 2013, we identified Oklahoma regulations regarding the payment of interest on accrued royalties which had not been recorded. We determined the amount of interest payable and recognized additional interest expense which was incorporated into our Consolidated Statements of Operations, as revised. The lack of Oklahoma legal and tax expertise on our staff led to these oversights. Management is reviewing the internal control weakness related to these omissions to determine the proper organizational structure in response.

        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 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor's attestation report) beginning with our fiscal year ending December 31, 2014. 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

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our efforts to comply with Section 404. If one or more material weaknesses persist or if we fail to establish 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 disclosure requirements that apply to other public companies.

        In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act (the "JOBS Act"). For as long as we remain an "emerging growth company" as defined in the JOBS Act, 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 of the Sarbanes-Oxley Act 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 be required to make payments under the Tax Receivable Agreement for certain tax benefits it 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 LLC 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 LLC Units with JONE for shares of Class A common stock (or resulting from a sale of JEH LLC Units 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 LLC. 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. 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 LLC 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 LLC 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 LLC 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 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

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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 its 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 third and fourth quarters of 2013:

	2013
	High		Low
3rd Quarter(1)	$	17.10	$	13.60
4th Quarter		18.14		13.15

(1)

Represents the period from July 24, 2013, the date on which our common stock began trading on the NYSE, through December 31, 2013.

        On March 5, 2014, the last sale price of our common stock, as reported on the NYSE, was $15.04 per share. As of March 5, 2014, there were 12,526,580 shares of Class A common stock outstanding held by approximately 6 stockholders of record and 36,836,333 shares of Class B common stock outstanding held by approximately 11 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 and our second lien term loan facility prohibit us from paying dividends.

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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.

        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, 2013.

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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, 2013.

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)		—		—		3,823,420	(2)
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		3,823,420

(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. On August 30, 2013, pursuant to the terms of the LTIP, our board of directors approved an award of 6,645 shares of restricted Class A common stock to each of the four non-employee directors of JONE, or 26,580 shares of restricted stock in the aggregate.

Issuer Purchases of Equity Securities

        None.

Sales of Unregistered Equity Securities

        None.

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, 2013, 2012, 2011 and 2010. 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)	2013			2012			2011			2010
Operating revenues
Oil and gas sales	$	258,063		$	148,967		$	167,261		$	97,523
Other revenues		1,106			847			1,022			933
Total operating revenues		259,169			149,814			168,283			98,456
Operating costs and expenses
Lease operating		27,781			23,097			21,548			16,296
Production taxes		12,865			5,583			5,333			2,206
Exploration		1,710			356			780			4,208
Depletion, depreciation and amortization		114,136			80,709			68,906			48,008
Impairment of oil and gas properties		14,415			18,821			31,970			10,727
Accretion of discount		608			533			413			490
General and administrative (including non-cash compensation expense)		31,902			15,875			16,679			11,423
Total operating expenses		203,417			144,974			145,629			93,358
Operating income		55,752			4,840			22,654			5,098
Other income (expense)
Interest expense		(30,774	)		(25,292	)		(21,994	)		(12,575	)
Net gain (loss) on commodity derivatives		(2,566	)		16,684			34,490			23,758
Gain on bargain purchase		—			—			26,208			—
Gain (loss) on sales of assets		(78	)		1,162			(859	)		8,644
Other income (expense), net		(33,418	)		(7,446	)		37,845			19,827
Income (loss) before income tax		22,334			(2,606	)		60,499			24,925
Income tax provision
Current		85			—			—			—
Deferred		(156	)		473			173			145
Total income tax provision		(71	)		473			173			145
Net income (loss)		22,405			(3,079	)		60,326			24,780
Net income attributable to non-controlling interests		24,591			—			—			—
Net income (loss) attributable to controlling interests	$	(2,186	)	$	(3,079	)	$	60,326		$	24,780
Earnings per share:
Basic and diluted	$	(0.17	)
Weighted average shares outstanding:
Basic and diluted		12,500
Other Supplementary Data:
EBITDAX(1)	$	204,997		$	135,741		$	127,960		$	74,771
Adjusted net income(2)		54,792			29,411			34,894			17,599

(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)	2013			2012			2011			2010
Statement of Cash Flow Data
Net cash flow provided by operating activities	$	163,896		$	84,550		$	120,217		$	44,624
Net cash used in investing activities		(383,600	)		(337,636	)		(318,963	)		(90,785	)
Net cash provided by financing activities		219,798			270,676			186,322			49,200
Net increase (decrease) in cash	$	94		$	17,590		$	(12,424	)	$	3,039

	As of December 31,
(in thousands of dollars)	2013		2012		2011		2010
Balance Sheet Data
Cash and cash equivalents	$	23,820	$	23,726	$	6,136	$	18,560
Other current assets		106,459		74,886		88,546		49,742
Total current assets		130,279		98,612		94,682		68,302
Property and equipment, net		1,315,995		1,010,742		743,575		495,613
Other long-term assets		41,705		41,332		42,878		21,379
Total assets	$	1,487,979	$	1,150,686	$	881,135	$	585,294
Current liabilities	$	179,668	$	93,421	$	108,494	$	60,938
Long-term debt		658,000		610,000		415,000		225,000
Other long-term liabilities		26,187		18,865		11,733		14,907
Total stockholders' / members' equity		624,124		428,400		345,908		284,449
Total liabilities and stockholders' / members' equity	$	1,487,979	$	1,150,686	$	881,135	$	585,294

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 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.

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        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)	2013			2012			2011			2010
Reconciliation of EBITDAX to net income
Net income (loss)	$	22,405		$	(3,079	)	$	60,326		$	24,780
Interest expense (excluding amortization of deferred financing costs)		28,097			21,748			19,054			10,610
Exploration expense		1,710			356			780			4,208
Income taxes		(71	)		473			173			145
Amortization of deferred financing costs		2,677			3,544			2,940			1,965
Depreciation and depletion		114,136			80,709			68,906			48,008
Impairment of oil and natural gas properties		14,415			18,821			31,970			10,727
Accretion expense		608			533			413			490
Other non-cash charges		79			129			(59	)		390
Stock compensation expense		10,838			570			1,134			—
Other compensation expense		2,719			—			—			—
Net (gain) loss on derivative contracts		2,566			(16,684	)		(34,490	)		(23,758	)
Current period settlements of matured derivative contracts		5,209			29,783			2,162			5,850
Amortization of deferred revenue		(469	)		—			—			—
Gain on bargain purchase		—			—			(26,208	)		—
Loss (gain) on sales of assets		78			(1,162	)		859			(8,644	)
EBITDAX	$	204,997		$	135,741		$	127,960		$	74,771

        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 gain on bargain purchase associated with the Southridge acquisition in 2011. 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)	2013			2012			2011			2010
Net income (loss)	$	22,405		$	(3,079	)	$	60,326		$	24,780
Net (gain) loss on derivative contracts		2,566			(16,684	)		(34,490	)		(23,758	)
Current period settlements of matured derivative contracts		5,209			29,783			2,162			5,850
Impairment of oil and gas properties		14,415			18,821			31,970			10,727
Non-cash stock compensation expense		10,838			570			1,134			—
Other non-cash compensation expense		2,719			—			—			—
Gain on bargain purchase		—			—			(26,208	)		—
Tax impact(1)		(3,360	)		—			—			—
Adjusted net income	$	54,792		$	29,411		$	34,894		$	17,599
Adjusted net income attributable to non-controlling interests		(51,182	)
Adjusted net income attributable to controlling interests	$	3,610
Earnings per share (basic and diluted)	$	(0.17	)
Net (gain) loss on derivative contracts		0.43
Current period settlements of matured derivative contracts		(0.01	)
Impairment of oil and gas properties		0.29
Non-cash stock compensation expense		0.02
Other non-cash compensation expense		—
Tax impact		(0.27	)
Adjusted earnings per share (basic and diluted)	$	0.29
Effective tax rate on net income attributable to controlling interests		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.

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 Anadarko and Arkoma

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basins of Texas and Oklahoma. We have drilled over 645 total wells, including over 460 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, 2013, our total estimated proved reserves were 89.0 MMBoe, of which 56% were classified as proved developed reserves. Approximately 19% of our total estimated proved reserves as of December 31, 2013 consisted of oil, 37% consisted of NGLs, and 44% consisted of natural gas.

Outlook

        We have identified 2,542 additional gross drilling locations in our areas of operation for 2014 and beyond, which we believe will enable us to drill and develop our resource base for many years. We believe that the commodity pricing environment will remain challenging for 2014, particularly for natural gas and NGLs. However, we believe that our drilling and completion cost efficiencies and our existing drilling inventory position us to continue generating attractive economic rates of return and to seek complementary acquisition and joint development opportunities.

        Our 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled 97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million, $310 million of which is expected to be used to drill and complete wells. The remainder of the 2014 capital expenditure budget is devoted to leasing and other discretionary expenditures. Please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—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 2014 budgeted capital expenditures with our cash flow from operations and projected availability under our senior secured revolving credit facility.

        We currently have ten rigs running in our two core areas, eight in the Cleveland and two in the Woodford. We currently expect to allocate our 2014 capital expenditure budget as follows:

	2014 Capital Expenditure Budget
	(in millions)
Drilling and completion:
Cleveland	$	250
Woodford		50
Other		10
Leasing		20
Other activities		20
All properties and activities	$	350

        NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have different uses and different pricing characteristics. Realized monthly pricing for NGLs, which comprised 36% of our 2012 production and 28% of our 2013 production, has recently approached five-year lows, principally due to oversupply in the market. Under our sale contracts in the Anadarko basin, we are generally paid market rates for the NGLs we produce, so the lower pricing has resulted in lower NGL revenues. However, under our sale contracts in the Arkoma Woodford, purchasers of NGLs have the ability to bypass the separate purchase of ethane below specified price thresholds and to purchase the ethane as part of a wet gas stream. Beginning in December 2012, purchasers have made this election and are paying wet natural gas prices for the gas stream produced from our Arkoma Woodford

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properties, which has resulted in increased natural gas production volumes and higher revenue from the ethane as an incremental energy component of net natural gas than we would receive were it sold separately at current prices. Although these elections can be made on a monthly basis and are entirely outside of our control, we anticipate, based on current forward price curves, that these purchasers will continue their elections to reject ethane and include it as part of the natural gas stream, which would have the effect of increasing our natural gas production volumes and decreasing NGL production volumes, in each case, by the amount of ethane rejected. Ethane constituted approximately 50% and 14% of our Woodford NGL production as of December 31, 2012 and December 31, 2013, respectively. A further or extended decline in NGL prices, or in oil or natural gas prices, could materially and adversely affect our financial position, our results of operations, the quantities of hydrocarbon reserves that we can economically produce and our access to capital.

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 collars, swaps and puts 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 price protection against declines in oil and gas prices, and may partially 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 current or former lenders under our senior secured revolving credit facility and potential hedge positions are 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 statements of financial position. During the year ended December 31, 2013, approximately 79% of our total production for oil, natural gas and NGLs was hedged. As of December 31, 2013, approximately 35% of our total forecasted production from proved reserves through 2018 was hedged, and the notional value of our hedge position was over $680 million. We do not anticipate any substantial changes in our hedging policy.

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        Our open positions as of December 31, 2013 were as follows:

	Year Ending December 31,
	2014			2015			2016			2017		2018
Oil positions(1):
Swaps:
Hedged volume (MBbl)		1,773			1,271			946			625		—
Weighted average price ($/Bbl)	$	91.12		$	89.27		$	87.49		$	84.92		—
Natural gas positions(2):
Swaps:
Hedged volume (MMcf)		13,940			10,663			8,450			6,860		—
Weighted average price ($/Mcf)	$	4.87		$	4.89		$	5.00		$	4.50		—
NGL positions(3):
Swaps:
Hedged volume (MBbl)		1,273			686			238			42		—
Weighted average price ($/Bbl)	$	29.27		$	32.05		$	49.82		$	64.39		—
Basis positions(4):
Swaps:
Hedged volume (MMcf)		7,260			4,350			1,000			—		—
Weighted average price ($/Mcf)	$	(0.35	)	$	(0.33	)	$	(0.28	)		—		—

(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 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 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 costs in each field on a units-of-production basis based on proved oil and natural gas reserve quantities.

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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.

        Accretion of discount.    Accretion of discounts 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 and other.    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 our second lien term loan facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This classification also includes the amortization of capitalized loan acquisition costs and bank fees associated with the debt and commitment fees on undrawn portions of our revolving credit facilities.

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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)
	2013			2012			Change			2012			2011			Change
Revenues:
Oil	$	145,146		$	66,921		$	78,225		$	66,921		$	73,769		$	(6,848	)
Natural gas		55,511			30,503			25,008			30,503			39,983			(9,480	)
NGLs		57,406			51,543			5,863			51,543			53,509			(1,966	)
Total oil and gas		258,063			148,967			109,096			148,967			167,261			(18,294	)
Other		1,106			847			259			847			1,022			(175	)
Total operating revenues		259,169			149,814			109,355			149,814			168,283			(18,469	)
Costs and expenses:
Lease operating		27,781			23,097			4,684			23,097			21,548			1,549
Production taxes		12,865			5,583			7,282			5,583			5,333			250
Exploration		1,710			356			1,354			356			780			(424	)
Depletion, depreciation and amortization		114,136			80,709			33,427			80,709			68,906			11,803
Impairment of oil and gas properties		14,415			18,821			(4,406	)		18,821			31,970			(13,149	)
Accretion of discount		608			533			75			533			413			120
General and administrative		31,902			15,875			16,027			15,875			16,679			(804	)
Total costs and expenses		203,417			144,974			58,443			144,974			145,629			(655	)
Operating income		55,752			4,840			50,912			4,840			22,654			(17,814	)
Other income (expenses):
Interest expense		(30,774	)		(25,292	)		(5,482	)		(25,292	)		(21,994	)		(3,298	)
Net gain (loss) on commodity derivatives		(2,566	)		16,684			(19,250	)		16,684			34,490			(17,806	)
Gain on bargain purchase		—			—						—			26,208			(26,208	)
Gain (loss) on sales of assets		(78	)		1,162			(1,240	)		1,162			(859	)		2,021
Total other income (expense)		(33,418	)		(7,446	)		(25,972	)		(7,446	)		37,845			(45,291	)
Income before income tax		22,334			(2,606	)		24,940			(2,606	)		60,499			(63,105	)
Income tax provision		(71	)		473			(544	)		473			173			300
Net income (loss)		22,405			(3,079	)		25,484			(3,079	)		60,326			(63,405	)
Net income (loss) attributable to non-controlling interests		24,591			—			24,591			—			—			—
Net income (loss) attributable to controlling interests	$	(2,186	)	$	(3,079	)	$	893		$	(3,079	)	$	60,326		$	(63,405	)

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	Years Ended December 31,							Years Ended December 31,
	2013		2012		Change			2012		2011		Change
Net production volumes:
Oil (MBbls)		1,557		746		811			746		811		(65	)
Natural gas (MMcf)		17,575		14,066		3,509			14,066		11,443		2,623
NGLs (MBbls)		1,724		1,773		(49	)		1,773		1,215		558
Total (MBoe)		6,210		4,863		1,347			4,863		3,933		930
Average net (Boe/d)		17,014		13,287		3,727			13,287		10,775		2,512
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	93.22	$	89.71	$	3.51		$	89.71	$	90.96	$	(1.25	)
Natural gas (per Mcf), unhedged		3.16		2.17		0.99			2.17		3.49		(1.32	)
NGLs (per Bbl), unhedged		33.30		29.07		4.23			29.07		44.04		(14.97	)
Combined (per Boe) realized, unhedged		41.56		30.63		10.93			30.63		42.53		(11.90	)
Average sales price, hedged:
Oil (per Bbl), hedged	$	87.86	$	87.30	$	0.56		$	87.30	$	99.02	$	(11.72	)
Natural gas (per Mcf), hedged		3.93		3.76		0.17			3.76		2.48		1.28
NGLs (per Bbl), hedged		33.26		34.22		(0.96	)		34.22		46.41		(12.19	)
Combined (per Boe) realized, hedged		42.40		36.76		5.64			36.76		41.98		(5.22	)
Average costs (per BOE):
Lease operating	$	4.47	$	4.75	$	(0.28	)	$	4.75	$	5.48	$	(0.73	)
Production taxes		2.07		1.15		0.92			1.15		1.36		(0.21	)
Depletion, depreciation and amortization		18.38		16.60		1.78			16.60		17.52		(0.92	)
General and administrative		5.14		3.26		1.88			3.26		4.24		(0.98	)

Results of Operations—Year ended December 31, 2013 as compared to year ended December 31, 2012

Operating revenues

        Oil and gas sales.    Oil and gas sales increased by $109.1 million (73.2%) to $258.1 million for the year ended December 31, 2013, as compared to $149.0 million for the year ended December 31, 2012. The majority of the increase (69.3%) was due to higher crude oil production volumes with the remainder of the increase being attributable to higher natural gas production volumes combined with higher prices for all products. Average daily production increased 28.0% to 17,014 Boe per day for the year ended December 31, 2013 as compared to 13,287 Boe per day for the year ended December 31, 2012. Crude oil production increased 108.7% from 746 MBbls for the year ended December 31, 2012 to 1,557 MBbls for the year ended December 31, 2013, primarily resulting from the wells acquired from Chalker, which generally have an oil production rate that is higher than our average historical Cleveland wells, combined with an increase in the number of wells drilled in 2013. Natural gas production increased 24.9% from 14,066 MMcf for the year ended December 31, 2012 to 17,575 MMcf for the year ended December 31, 2013, due to new wells added through drilling and the Chalker acquisition. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $89.71 per Bbl to $93.22 per Bbl, or 3.9%, year over year. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $2.17 per Mcf to $3.16 per Mcf, or 45.6%, year over year. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $29.07 per Bbl to $33.30 per Bbl, or 14.6%.

Costs and expenses

        Lease operating.    Lease operating expense increased by $4.7 million (20.3%) to $27.8 million for the year ended December 31, 2013, as compared to $23.1 million for the year ended December 31,

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2012. The increase occurred in correlation with the 28.0% increase in production volumes. On a per unit basis, lease operating expense decreased by $0.28 per Boe or 5.9%, from $4.75 to $4.47 per Boe, for the year ended December 31, 2013 as compared to the year ended December 31, 2012. 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 Chalker wells (as compared to our historical set of wells); however, on a per unit basis, lease operating expense decreased as the Chalker properties have an initial production rate that is higher than our average historical Cleveland well.

        Production taxes.    Production taxes increased by $7.3 million (130.4%) to $12.9 million for the year ended December 31, 2013, as compared to $5.6 million for the year ended December 31, 2012. Overall production taxes increased in conjunction with the 73.2% increase in revenue; however, the average effective rate increased from 3.7% for the year ended December 31, 2012 to 5.0% for the year ended December 31, 2013. Production taxes were at a higher rate during 2013 due to the acquisition and drilling of the Chalker properties in Texas, which imposes a higher initial tax rate (7.5%) than Oklahoma (1%), where many of our other properties are located.

        Exploration.    Exploration expense increased from $0.4 million for the year ended December 31, 2012 to $1.7 million for the year ended December 31, 2013. The increase was related to seismic expenses incurred in the Arkoma.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization increased by $33.4 million (41.4%) to $114.1 million for the year ended December 31, 2013, as compared to $80.7 million for the year ended December 31, 2012. The increase was primarily the result of continued drilling activity and the acquisition of the Chalker properties at the end of 2012. On a per unit basis, depletion expense increased $1.78 per Boe or 10.7% from $16.60 per Boe for the year ended December 31, 2012 as compared to $18.38 per Boe for the year ended December 31, 2013. The per unit increase resulted from the acquisition of the Chalker and Sabine properties, the write off of proved undeveloped reserves attributable to the Southridge joint development agreement, and the higher cost to drill wells in 2013 compared to historical wells. The write-off of the Southridge reserves will increase depletion expense per Boe, provided all other inputs are constant.

        Impairment of oil and gas properties.    We had impairment charges on oil and gas properties of $14.4 million for the year ended December 31, 2013 as compared to impairment charges of $18.8 million for the year ended December 31, 2012. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to drill the undeveloped acreage and associated unproved reserves. In 2012, all of the impairment charges related to inactive fields and minor plays, where the Company did not have any development. None of the 2013 charges were in the Cleveland formation.

        General and administrative.    General and administrative expenses increased by $16.0 million (100.6%) to $31.9 million for the year ended December 31, 2013, as compared to $15.9 million for the year ended December 31, 2012. Of this increase, $10.8 million related to stock compensation expense (of which $9.6 million was related to the immediate vesting of certain shares on the IPO date) and $2.7 million related to a one-time non-cash distribution to management related to the Monarch incentive plan. 2012 includes $0.6 million of stock compensation expense. Excluding these non-cash items, general and administrative expenses increased $3.0 million (19.6%) to $18.3 million for the year ended December 31, 2013, as compared to $15.3 million for the year ended December 31, 2012. The increase in cash general and administrative expense is attributable to an increase in salaries and benefits due to an increase in headcount to support our increased drilling activity, which was partially offset by an increase in overhead reimbursements, and an increase in professional fees incurred as a result of being a public company for a portion of 2013. On a per unit basis, cash general and

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administrative expenses decreased from $3.15 per Boe for the year ended December 31, 2012 to $2.95 per Boe for the year ended December 31, 2013. The increase in activity resulting from drilling and the acquisition of the Chalker properties significantly increased production (28.0% on a Boe basis) but did not result in a proportional increase in general and administrative expenses.

        Interest and other.    Interest and other financing expenses increased by $5.5 million (21.7%) to $30.8 million for the year ended December 31, 2013, as compared to $25.3 million for the year ended December 31, 2012. Of the total expense, interest paid under our bank debt totaled $26.3 million and $20.6 million for the years ended December 31, 2013 and 2012, respectively. We increased our debt at the end of 2012 to fund the Chalker acquisition. In July 2013, a majority of this was paid down with the proceeds from the initial public offering. At the end of 2013, we increased our debt again to fund the Sabine acquisition. Our average debt outstanding for the year ended December 31, 2013 was $544.9 million as compared to $428.1 million for the year ended December 31, 2012 and the weighted average interest rate incurred on the outstanding borrowings was 4.82% and 4.96%, respectively.

        Gain (loss) on commodity derivatives.    We had a net loss on commodity derivatives of $2.6 million for the year ended December 31, 2013 as compared to a net gain of $16.7 million for the year ended December 31, 2012. The decrease is attributable to increases in crude oil and natural gas prices year over year (crude oil prices averaged $97.97 during 2013 as compared to $94.20 during 2012 and natural gas prices averaged $3.65 in 2013 as compared to $2.79 in 2012) combined with increases in future crude oil prices from 2012 to 2013 as compared to decreases in future crude oil prices from 2011 to 2012. The 12-month forward prices at December 31, 2013 for crude oil averaged $95.66 per Bbl as compared to $93.09 per Bbl at December 31, 2012, while the 12-month forward prices at December 31, 2012 averaged $93.09 per Bbl as compared to $98.77 per Bbl at December 31, 2011.

        Gain (loss) on sales of assets.    The gain on sales of assets decreased from $1.2 million for the year ended December 31, 2012 to a loss of $0.1 million for the year ended December 31, 2013, due to the sale of properties in the North Barnett Shale during the first quarter of 2012 compared with no significant sales of properties in 2013.

        Income taxes.    The provision for income taxes calculated for 2013 reflects our reorganization and recapitalization which occurred in connection with the Company's initial public offering. Following the IPO, the Company is subject to federal and state income and franchise taxes, while only the Texas franchise tax applied to JEH LLC prior to the IPO. The income tax expense decreased from $0.5 million for the year ended December 31, 2012 to a benefit of $0.1 million for the year ended December 31, 2013. The 2012 income tax expense solely reflected the Texas franchise tax liability for JEH LLC. The 2013 income tax benefit included a benefit for federal income taxes reduced by the Texas franchise tax expense. The non-controlling interest was allocated its proportionate share of the Texas franchise tax expense incurred during 2013.

Results of Operations—Year ended December 31, 2012 as compared to year ended December 31, 2011

Operating Revenues

        Oil and gas sales.    Our oil and gas sales decreased by $18.3 million (10.9%) to $149.0 million during the year ended December 31, 2012, as compared to $167.3 million for the year ended December 31, 2011. The revenue decrease was primarily due to lower commodity prices for natural gas and NGLs and lower oil production volumes. Realized average natural gas prices, without derivatives, decreased 37.8% during the year, falling to $2.17 per Mcf in 2012 from $3.49 per Mcf in 2011. Realized average NGL prices, without derivatives, decreased 34.0%, falling to $29.07 per Bbl in 2012 from $44.04 per Bbl in 2011. Oil production declined to 746 MBbls in 2012 from 811 MBbls, a decrease of 8.0%, as we pursued more wet gas prospects in 2012, increasing natural gas and NGL production by 22.9% and 45.9%, respectively.

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Costs and Expenses

        Lease operating.    Our lease operating expense increased by approximately $1.6 million (7.4%) to $23.1 million during the year ended December 31, 2012, as compared to $21.5 million for the year ended December 31, 2011. This increase was primarily due to an increase in the number of operated wells due to continued drilling activity. On a per unit basis, lease operating expense decreased $0.73 per Boe to $4.75 per Boe in 2012 from $5.48 per Boe in 2011, due to the emphasis on drilling liquids-rich prospects, which increased the overall productivity of our properties, as the increase in the production of natural gas and NGLs offset the decline in oil production.

        Production taxes.    Our production taxes increased by $0.3 million to $5.6 million (5.7%) during the year ended December 31, 2012, as compared to $5.3 million during the year ended December 31, 2011. Although total revenues decreased, the increase in production tax expense was primarily due to an increase in the backlog of wells at the Railroad Commission of Texas, or TRRC, waiting for approval of tax rate reductions. We currently estimate that we have approximately $1.9 million in pending tax reductions with the TRRC.

        Exploration.    Exploration expenses decreased by $0.4 million to $0.4 million (50.0%) during the year ended December 31, 2012, as compared to the $0.8 million during the year ended December 31, 2011. The decrease was primarily due to no dry hole cost charged to expense in 2012.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization increased by $11.8 million to $80.7 million (17.1%) for the year ended December 31, 2012, as compared to $68.9 million for the year ended December 31, 2011. This was primarily a result of an increase in production and continued drilling activity. On a per unit basis, depletion expense decreased to $16.60 per Boe for 2012, compared to $17.52 per Boe for 2011 as overall production increased.

        Impairment of oil and gas properties.    Our impairment of oil and gas properties decreased by $13.2 million to $18.8 million for the year ended December 31, 2012, as compared to $32.0 million for the year ended December 31, 2011. Our impairment charges relate to inactive fields and minor plays, which we are not currently developing. None of these charges were in the Cleveland or Woodford shale formations. In 2011, impairment charges related to these fields, along with a number of sales of minor properties, significantly reduced the remaining carrying values of these fields, thereby reducing further impairment.

        General and administrative.    Our general and administrative expenses decreased by $0.8 million to $15.9 million (4.8%) during the year ended December 31, 2012, as compared to $16.7 million during the year ended December 31, 2011. The decrease was attributable to decreases in stock compensation expenses and legal expenses in 2012 versus 2011, partially offset by an increase in staff. On a per unit basis, general and administrative expense decreased in 2012 to $3.26 per Boe from $4.24 per Boe, due to an increase in production without a commensurate rise in expense.

        Interest and other.    Our interest and other financing expenses increased by $3.3 million to $25.3 million (15.0%) during the year ended December 31, 2012, as compared to $22.0 million during the year ended December 31, 2011, primarily due to an $81.9 million increase in average outstanding debt for 2012 as compared to the prior year. The increase in average outstanding debt was primarily used to finance the Chalker acquisition and continued drilling activity.

        Gain on commodity derivatives.    Our net gain on commodity derivatives decreased by $17.8 million to $16.7 million during the year ended December 31, 2012, as compared to $34.5 million during the year ended December 31, 2011. The 2012 results include gains attributable to a drop in crude oil prices, compounded by an increase in oil production volumes hedged. The 12-month forward prices at December 31, 2012 for crude oil averaged $93.22 per Bbl, while the 12-month forward prices at December 31, 2011 averaged $98.77 per Bbl. These gains were reduced by higher gas prices, year over

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year. The 12-month forward prices at December 31, 2012 for natural gas averaged $3.54 per MMBtu, while the 12-month forward prices at December 31, 2011 averaged $3.25 per MMBtu. The 2011 net gain was primarily attributable to a decrease in natural gas prices. The 12-month forward prices at December 31, 2011 for natural gas averaged $3.25 per MMBtu, while the 12-month forward prices at December 31, 2010 averaged $4.55 per MMBtu.

        Gain (loss) on sales of assets.    Our gain (loss) on sales of assets increased from a loss of $0.9 million during the year ended December 31, 2011 to a gain of $1.2 million during the year ended December 31, 2012, primarily due to the sale in 2012 of properties in the North Barnett Shale at a gain compared to less significant sales of properties in 2011.

Liquidity and Capital Resources

        Historically, our primary sources of liquidity have been private and public sales of our 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 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 future 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 senior secured revolving credit facility, 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, 2013 reflects a working capital deficit as we use the available balance of the borrowing base under our senior secured revolving credit facility to manage cash flow. The available borrowing base of $77.0 million exceeds the working capital deficit of $49.4 million.

        Our 2014 capital budget will be primarily focused on the development of existing core areas in the Cleveland and Woodford plays through exploitation and development. The ultimate amount of capital we will expend may fluctuate materially based on market conditions, the economic returns being realized and the success of our drilling results as the year progresses. We expect to fund our entire 2014 capital budget with cash flows from operations and borrowings under our senior secured revolving credit facility. 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 prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. Because leases covering less than 3% of our core property acreage are set to expire through December 31, 2014, and all but 50 PUD locations currently are held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with low risk of losing significant acreage. We consistently 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 timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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        The following table summarizes our cash flows for the years ended December 31, 2011, 2012 and 2013:

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Net cash provided by operating activities	$	163,896		$	84,550		$	120,217
Net cash used in investing activities		(383,600	)		(337,636	)		(318,963	)
Net cash provided by financing activities		219,798			270,676			186,322
Net increase (decrease) in cash	$	94		$	17,590		$	(12,424	)

Cash Flow Provided by Operating Activities

        Net cash provided by operating activities was $163.9 million for the year ended December 31, 2013 as compared to cash provided by operating activities of $84.6 million for the year ended December 31, 2012. The increase in operating cash flows was primarily due to a $109.1 million increase in oil and gas revenues for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in revenue was primarily driven by a 108.7% increase in oil production volumes as a result of drilling and the Chalker acquisition in the fourth quarter of 2012, combined with increases in crude oil and natural gas prices and other volumes. The increase in cash flow was offset by increased capital spending resulting from an increase in drilling activity from four rigs running at December 31, 2012 to ten rigs running at December 31, 2013.

        Net cash provided by operating activities was $84.6 million for the year ended December 31, 2012 as compared to cash provided by operations of $120.2 million for the year ended December 31, 2011. The decrease in operating cash flows in 2012 compared to 2011 was primarily due to the decrease of $18.3 million in revenues year over year on relatively flat operating expenses. While production increased, the 37.8% drop in realized average natural gas prices and the 34.0% decline in realized average NGL prices primarily drove the decrease in revenues. The reduction in net cash provided by operating activities also stemmed from changes in working capital. Receivables from joint interest owners declined $13.1 million due to the Company retaining a higher working interest ownership in wells being drilled and a reduction in the number of active drilling rigs. In addition, oil and gas sales payable decreased $8.4 million.

        Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and 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."

Cash Flow Used in Investing Activities

        Net cash used in investing activities was $383.6 million for the year ended December 31, 2013 as compared to cash used in investing activities of $337.6 million for the year ended December 31, 2012. The increase was primarily driven by higher capital expenditures which increased $117.5 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012 due to an increase in drilling activity. The increase in capital expenditures was partially offset by the decrease in acquisitions as the purchase price of the Sabine acquisition ($193.5 million) at the end of 2013 was less than that of the Chalker acquisition ($253.5 million) at the end of 2012. Additionally, cash flows from current period settlements of our commodity derivatives instruments decreased by $21.1 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012 as a result of an increase in crude oil and natural gas prices. Finally, we received cash proceeds of $9.2 million from the sale of North Barnett properties in the first quarter of 2012, and experienced no meaningful sales of properties occurring during the year ended December 31, 2013.

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        We had net cash used in investing activities of $337.6 million for the year ended December 31, 2012 as compared to cash used in investing of $319.0 million for the year ended December 31, 2011. The increase in cash used in investing activities was primarily related to the Chalker acquisition in 2012 which was larger than the Southridge acquisition in 2011. This incremental acquisition investment was partially offset by a decline in net drilling and equipment expenditures and an increase in gains realized through commodity derivatives in 2012.

        We expect our 2014 capital expenditures to be approximately $350 million, which is a 46% increase over the $240 million incurred for 2013. 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 $219.8 million for the year ended December 31, 2013 as compared to net cash provided by financing activities of $270.7 million for the year ended December 31, 2012. The decrease in cash flows provided by financing activities was primarily due to net borrowings of $47.3 million during 2013 as compared to $185.7 million during 2012. The net proceeds from the initial public offering of our Class A common stock of $172.5 million (net of expenses) in the third quarter of 2013 were used to repay debt of $167.0 million during the year ended December 31, 2013.

        Net cash provided by financing activities was $270.7 million during the year ended December 31, 2012 as compared to cash provided by financing of $186.3 million during the year ended December 31, 2011. The increase in cash flows provided by financing activities was primarily due to an $85.0 million contribution of new equity capital by our existing owners for preferred units. Borrowings under our credit facility, net of repayments, remained relatively unchanged at $185.7 million in 2012 and $186.3 million in 2011.

Credit Facilities

        Senior Secured Revolving Credit Facility.    JEH LLC has a $1 billion senior secured revolving credit facility with Wells Fargo Bank, N.A. as the administrative agent, and a syndicate of lenders. Availability under the senior secured revolving credit facility is subject to a borrowing base, which is currently $575 million. The senior secured revolving credit facility matures in November 2017. As of December 31, 2013, JEH LLC had borrowings of $498 million outstanding under the senior secured revolving credit facility. JEH LLC's obligations under the senior secured revolving credit facility are guaranteed by Jones Energy, Inc. and JEH LLC's domestic subsidiaries and are secured by substantially all of its and their assets (other than equity interests of JEH LLC held by Jones Energy, Inc.).

        The borrowing base under our senior secured revolving credit facility was redetermined by the lenders on December 18, 2013, which was deemed to be the redetermination scheduled for August 1, 2013, and will be redetermined on April 1, 2014 and semi-annually thereafter on February 1 and August 1 of each year. JEH LLC and the administrative agent (acting at the direction of lenders holding at least 66²/3% of the outstanding loans and letter of credit obligations) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the

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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 will also be reduced in certain circumstances as a result of our issuance of unsecured notes by an amount equal to 25% of the principal amount of unsecured notes issued in excess of $400 million, our termination of certain hedging positions and our consummation of certain asset sales.

        If the aggregate outstanding principal amount of the revolving loans under the senior secured revolving credit facility 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 and, if necessary to eliminate such excess, cash collateralize outstanding letters of credit 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, we must make such prepayment and/or deposit of cash collateral on the date we receive cash proceeds as a result of such disposition, and if such a borrowing base deficiency results from certain 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.

        On January 29, 2014, JEH LLC entered into an Eighth Amendment (the "Eighth Amendment") to the senior secured revolving credit facility. The Eighth Amendment amends the senior secured revolving credit facility to, among other things, (1) reduce the commitment fee and interest rate margin applicable to loans under the senior secured revolving credit facility, (2) increase the basket available for issuance of senior unsecured notes from $300 million to $500 million, (3) provide additional flexibility with respect to entrance into derivative arrangements in anticipation of acquisitions of oil and gas properties and (4) provide for a guarantee of JEH LLC's obligations under the senior secured revolving credit facility by Jones Energy, Inc. The foregoing description of the Eighth Amendment is not complete and is qualified by reference to the complete document, which is attached hereto as Exhibit 10.20 and is incorporated herein by reference.

        Interest on loans under our senior secured revolving credit facility is calculated at a base rate (being at JEH LLC's option, either (i) the per annum rate appearing on Reuters Screen LIBOR01 Page, or the LIBO Rate, for the applicable interest period or (ii) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A., (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 2.50% based on the actual amount borrowed compared to the borrowing amount and the base rate selected. JEH LLC 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 senior secured revolving credit facility 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, or prepay any of the second lien term loans (with an exception allowing us to repay the second lien term loans from the proceeds of the issuance of senior unsecured notes);

•

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 senior secured revolving credit facility 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 LLC 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).

        Jones Energy, Inc. and its consolidated subsidiaries are also required under the senior secured revolving credit facility 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 senior secured revolving credit facility. If an event of default exists under the credit agreement, the lenders will be able to accelerate the obligations outstanding under the credit agreement and exercise other rights and remedies. Our senior secured revolving credit facility contains customary events of default, including a change of control, as defined in the senior secured revolving credit facility.

        Second Lien Term Loan Facility.    In addition, JEH LLC has a $160 million second lien term loan facility with Wells Fargo Energy Capital, Inc., as the administrative agent, and a syndicate of lenders. The second lien term loan facility matures in May 2018. JEH LLC currently has $160 million in loans outstanding under the second lien facility. An intercreditor agreement governs the relationship between the lenders under the senior secured revolving credit facility and the lenders under the second lien term loan facility.

        The principal amount of the loans borrowed under the second lien term loan facility is due in full on the maturity date. Interest on our second lien term loan facility is calculated at a base rate (being, at JEH LLC's option, either (i) the LIBO Rate for the applicable interest period (but in any event not less than 2.00%) or (ii) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A., (y) the federal funds rate plus 0.50% and (z) the one-month adjusted LIBO Rate plus 1.00%, plus a margin of either 6.0% or 7.0% based on the base rate selected.

        Our second lien term loan facility contains various restrictive covenants that are similar to those in our senior secured revolving credit facility.

Off-Balance Sheet Arrangements

        At December 31, 2013, 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, 2013:

	Payments Due by Period
	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		Thereafter
	(dollars in thousands)
Long-term debt obligations	$	658,000	$	—	$	498,000	$	160,000	$	—
Interest expense		121,556		29,691		86,774		5,090		—
Drilling rig commitments		19,727		19,727		—		—		—
Commodity derivative obligations		10,855		10,665		190		—		—
Operating lease obligations		1,637		586		1,051		—		—
Asset retirement obligations, discounted		10,963		2,590		812		493		7,068
Total	$	799,283	$	63,259	$	586,827	$	165,583	$	7,068

Critical Accounting Policies and Estimates

        The discussion and analysis of our financial condition and results of operations are based upon 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

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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.

        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 reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. 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. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in 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.

        Unproved Properties—Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and gas properties.

        Exploration Costs—Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, amortization of unproved leasehold costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

        Proved Oil and Gas Properties—Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil, gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

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        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.

        Depreciation, Depletion and Amortization—Depreciation, depletion and amortization, or DD&A, of capitalized costs of proved oil and gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A purposes on the basis of a reasonable aggregation of properties producing from or expected to be developed in a basin or formation. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

        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 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.

        Revenue Recognition.    We recognize oil, gas and NGL revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured (sales method). Oil and natural gas sold is not significantly different from our share of production.

        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 statements of financial position (see Note 4, "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

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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.

Recent Accounting Pronouncements

        In December 2011, the Financial Accounting Standards Board, or the FASB, issued an Accounting Standards Update, or ASU, that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013. We have provided all required disclosures for the periods presented as they pertain to its commodity derivative instruments (see Note 4, "Fair Value Measurement" in Item 8. Financial Statements and Supplementary Data). These disclosure requirements did not affect our operating results, financial position, or cash flows.

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.

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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, 2013 was a net asset of $23.4 million.

        As of December 31, 2013, we have hedged approximately 35% of our total forecasted production from proved reserves through December 31, 2018. For information regarding the terms of these hedges, please see "—Basis of presentation—Hedging" above. The production hedged thereby is consistent with the anticipated monthly production levels in the December 31, 2013 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."

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 and we do not have a formal process in place to evaluate and assess the credit standing of our partners or customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such parties as we deem appropriate under the circumstances. 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 indebtedness. The terms of the senior secured revolving credit facility and the second lien term loan 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% on the revolver and 6.0-7.0% on the term loan depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. During the year

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ended December 31, 2013, borrowings under the senior secured revolving credit facility and second lien term loan bore interest at a weighted average rate of 3.01% and 9.19%, 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 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. In light of the previously identified material weakness described below and the insufficient time to test the operational effectiveness of our new processes and controls, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2013.

Changes in Internal Control over Financial Reporting

        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.

        Management has taken steps to address the causes of our audit adjustments and to improve our internal control over financial reporting, 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. Since July 2010, we have hired three accounting managers along with a number of degreed staff accountants. This team has enabled us to expedite our month-end close process, thereby facilitating the timely preparation of financial reports. Likewise, we strengthened our internal control environment through the addition of skilled accounting personnel. 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. We have designed but not fully implemented new processes and controls to remediate the material weakness identified. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially

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affect, our internal control over financial reporting. In the fourth quarter of 2013 we initiated our SOX implementation process and hired a consulting firm to assist us in documenting our processes and controls. Initial testing of our controls will commence in the first quarter of 2014. As of December 31, 2013, insufficient time has elapsed to test the operational effectiveness of these new controls, and as such, we are unable to conclude the material weakness has been remediated.

Management's Assessment of Internal Control over Financial Reporting

        The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (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 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. This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014.

Item 9B.    Other Information

        None.

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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.

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.

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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.

83

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.
	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).
	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).
	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. 2013 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 September 4, 2013).
	10.8	†	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).

84

Exhibit No.			Description
	10.9	†	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).
	10.10		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).
	10.11		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).
	10.12		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).
	10.13		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).
	10.14		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).
	10.15		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).
	10.16		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).
	10.17		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).
	10.18		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).
	10.19	*	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.
	10.20	*	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.
	10.21	*	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.

85

Exhibit No.			Description
	10.22		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).
	10.23		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).
	10.24		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).
	10.25		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).
	10.26		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).
	10.27		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).
	10.28		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).
	10.29		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).
	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, 2013
	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.

86

Exhibit No.			Description
	101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase Document.

*—filed herewith

**—furnished herewith

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

87

SIGNATURES

        Pursuant to the requirements 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 14, 2014	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 indicated.

Name	Title	Date
/s/ JONNY JONES Jonny Jones	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	March 14, 2014
/s/ MIKE S. MCCONNELL Mike S. McConnell	Director and President	March 14, 2014
/s/ ROBERT J. BROOKS Robert J. Brooks	Executive Vice President and Chief Financial Officer (Principal Accounting and Financial Officer)	March 14, 2014
/s/ HOWARD I. HOFFEN Howard I. Hoffen	Director	March 14, 2014
/s/ GREGORY D. MYERS Gregory D. Myers	Director	March 14, 2014
/s/ HALBERT S. WASHBURN Halbert S. Washburn	Director	March 14, 2014
/s/ ALAN D. BELL Alan D. Bell	Director	March 14, 2014

88

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"—Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

        "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 when 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 natural gas or oil 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 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 and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

        "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."

89

        "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 recognized 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.

90

        "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.

91

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	F-31
Supplemental Quarterly Financial Information	F-35

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, 2013 and 2012 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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 14, 2014

F-2

Jones Energy, Inc

Consolidated Balance Sheets

December 31, 2013 and 2012

(in thousands of dollars)	December 31, 2013			December 31, 2012
Assets
Current assets
Cash	$	23,820		$	23,726
Restricted Cash		45			—
Accounts receivable, net
Oil and gas sales		51,233			29,684
Joint interest owners		42,481			21,876
Other		1,459			4,590
Commodity derivative assets		8,837			17,648
Other current assets		2,392			1,088
Deferred tax assets		12			—
Total current assets		130,279			98,612
Oil and gas properties, net, at cost under the successful efforts method		1,312,551			1,007,344
Other property, plant and equipment, net		3,444			3,398
Commodity derivative assets		25,398			25,199
Other assets		15,006			16,133
Deferred tax assets		1,301			—
Total assets	$	1,487,979		$	1,150,686
Liabilities and Stockholders' / Members' Equity
Current liabilities
Trade accounts payable	$	89,430		$	38,036
Oil and gas sales payable		66,179			45,860
Accrued liabilities		10,805			5,255
Commodity derivative liabilities		10,664			4,035
Deferred tax liabilities		—			61
Asset retirement obligations		2,590			174
Total current liabilities		179,668			93,421
Long-term debt		658,000			610,000
Deferred revenue		14,531			—
Commodity derivative liabilities		190			7,657
Asset retirement obligations		8,373			9,332
Deferred tax liabilities		3,093			1,876
Total liabilities		863,855			722,286
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity		—			428,400
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding		13			—
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding		37			—
Additional paid-in-capital		173,169			—
Retained earnings (deficit)		(2,186	)		—
Stockholders' / members' equity		171,033			428,400
Non-controlling interest		453,091			—
Total stockholders' / members' equity		624,124			428,400
Total liabilities and stockholders' / members' equity	$	1,487,979		$	1,150,686

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, 2013, 2012 and 2011

	Year Ended December 31,
(in thousands except per share data)	2013			2012			2011
Operating revenues
Oil and gas sales	$	258,063		$	148,967		$	167,261
Other revenues		1,106			847			1,022
Total operating revenues		259,169			149,814			168,283
Operating costs and expenses
Lease operating		27,781			23,097			21,548
Production taxes		12,865			5,583			5,333
Exploration		1,710			356			780
Depletion, depreciation and amortization		114,136			80,709			68,906
Impairment of oil and gas properties		14,415			18,821			31,970
Accretion of discount		608			533			413
General and administrative (including non-cash compensation expense)		31,902			15,875			16,679
Total operating expenses		203,417			144,974			145,629
Operating income		55,752			4,840			22,654
Other income (expense)
Interest expense		(30,774	)		(25,292	)		(21,994	)
Net gain (loss) on commodity derivatives		(2,566	)		16,684			34,490
Gain on bargain purchase		—			—			26,208
Gain (loss) on sales of assets		(78	)		1,162			(859	)
Other income (expense), net		(33,418	)		(7,446	)		37,845
Income (loss) before income tax		22,334			(2,606	)		60,499
Income tax provision
Current		85			—			—
Deferred		(156	)		473			173
Total income tax provision		(71	)		473			173
Net income (loss)		22,405			(3,079	)		60,326
Net income attributable to non-controlling interests		24,591			—			—
Net income (loss) attributable to controlling interests	$	(2,186	)	$	(3,079	)	$	60,326
Earnings per share:
Basic and diluted	$	(0.17	)
Weighted average shares outstanding:
Basic and diluted		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, 2013, 2012 and 2011

	Common Stock
	Class A				Class B
									Members' Equity			Additional Paid-in- Capital		Retained Deficit			Non-controlling Interest			Total Stockholders' / Members' Equity
(amounts in thousands)	Shares		Value		Shares		Value
Balance at December 31, 2010		—	$	—		—	$	—	$	284,449		$	—	$	—		$	—		$	284,449
Stock-compensation expense		—		—		—		—		1,134			—		—			—			1,134
Net income		—		—		—		—		60,326			—		—			—			60,326
Balance at December 31, 2011		—		—		—		—		345,909			—		—			—			345,909
Issuance of Class C preferred units		—		—		—		—		85,000			—		—			—			85,000
Stock-compensation expense		—		—		—		—		570			—		—			—			570
Net income (loss)		—		—		—		—		(3,079	)										(3,079	)
Balance at December 31, 2012		—		—		—		—		428,400			—		—			—			428,400
Issuance of common stock		12,500		13		36,836		37		—			—		—			—			50
Proceeds from the sale of common stock		—		—		—		—		—			172,431		—			—			172,431
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		—		—		—		—		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

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, 2013, 2012 and 2011

	Year Ended December 31,
(in thousands of dollars)	2013			2012			2011
Cash flows from operating activities
Net income (loss)	$	22,405		$	(3,079	)	$	60,326
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Exploration expense		—			—			478
Depletion, depreciation, and amortization		114,136			80,709			68,906
Impairment of oil and gas properties		14,415			18,821			31,970
Accretion of discount		608			533			413
Amortization of debt issuance costs		2,677			3,544			2,940
Stock compensation expense		10,838			570			1,134
Other non-cash compensation expense (Note 9)		2,719			—			—
Amortization of deferred revenue		(469	)		—			—
Gain on commodity derivatives		2,566			(16,684	)		(34,490	)
Gain on bargain purchase price		—			—			(26,208	)
(Gain) loss on sales of assets		78			(1,162	)		859
Deferred income tax provision		(156	)		473			173
Other—net		79			129			(59	)
Changes in assets and liabilities
Accounts receivable		(41,481	)		11,568			(32,593	)
Other assets		163			1,873			(3,360	)
Accounts payable and accrued liabilities		35,318			(12,745	)		49,728
Net cash provided by operations		163,896			84,550			120,217
Cash flows from investing activities
Additions to oil and gas properties		(197,618	)		(125,493	)		(157,046	)
Acquisition of properties		(193,496	)		(249,007	)		(168,480	)
Proceeds from sales of assets		1,607			9,158			6,747
Acquisition of other property, plant and equipment		(1,634	)		(969	)		(1,735	)
Current period settlements of matured derivative contracts		7,586			28,675			1,551
Change in restricted cash		(45	)		—			—
Net cash used in investing		(383,600	)		(337,636	)		(318,963	)
Cash flows from financing activities
Proceeds from issuance of long-term debt		220,000			233,243			316,500
Repayment under long-term debt		(172,000	)		(38,243	)		(126,500	)
Payment of debt issuance costs		(683	)		(9,324	)		(3,678	)
Issuance of preferred units		—			85,000			—
Proceeds from sale of common stock, net of expenses of $15.1 million		172,481			—			—
Net cash provided by financing		219,798			270,676			186,322
Net increase (decrease) in cash		94			17,590			(12,424	)
Cash
Beginning of period		23,726			6,136			18,560
End of period	$	23,820		$	23,726		$	6,136
Supplemental disclosure of cash flow information
Cash paid for interest	$	25,414		$	20,759		$	18,151
Change in accrued additions to oil and gas properties		41,945			3,355			26,774
Noncash acquisition of oil and gas properties		—			2,918			—
Current additions to ARO		1,516			662			4,077
Noncash distributions to members (Note 9)		10,000			—			—

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

F-6

Jones Energy, Inc.

Notes to 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, 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.

        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. 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.

        Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Jones Energy, Inc.'s initial public offering ("IPO") on July 29, 2013, the pre-IPO owners of JEH converted their existing membership interests in JEH into JEH Units and amended the existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH Units and to admit Jones Energy, Inc. as the sole managing member of JEH. Jones Energy, Inc.'s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. Only Class A common stock was offered to investors pursuant to the IPO. 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. The Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by the Company's stockholders generally. As a result of the IPO, the pre-IPO owners retained 74.7% 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 (loss) earned prior to the IPO date is reflected in the net income (loss) 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 acquisition, exploration, and production of oil and natural gas properties in the mid-continent United States. The Company's assets are located within two distinct basins in the Texas Panhandle and Oklahoma, the Anadarko Basin and the Arkoma Basin, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

        We identified an error in our previously issued financial statements which would have been material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period. Therefore we have revised our Consolidated Statement of Operations for the years ended December 31, 2012 and 2011 to record $0.6 million and $0.8 million, respectively of additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. As a result, net income decreased for the years ended December 31, 2012 and 2011 by $0.6 million and $0.8 million,

F-7

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

1. Organization and Description of Business (Continued)

respectively. The balance sheet impacts of the revision are increases in accrued liabilities and decreases in members' equity of $0.6 million and $1.4 million at December 31, 2011 and 2012, respectively. These revisions had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows. We have determined that these errors are not material to our consolidated financial statements for the years ended December 31, 2012 and 2011.

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, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

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 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").

Financial Instruments

        Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company's credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company's credit risk. Derivative instruments are recorded at fair value, as discussed below.

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.

F-8

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Management monitors the soundness of the financial institutions and believes the Company's risk is negligible.

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 consist primarily of 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, 2013 and 2012, 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. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 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, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% 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.

F-9

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that 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. Oil and gas properties consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

        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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

        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. The Company did not capitalize any interest in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

F-10

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

        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 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. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        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 incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

        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 activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

        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.

F-11

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Other Property, Plant and Equipment

        Other property, plant and equipment consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

        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. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

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, 2013, 2012 and 2011, 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 Jones 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 4, "Fair Value Measurement," for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

        The Company's asset retirement obligations 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

F-12

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

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. A summary of the Company's ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are 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.

Production Costs

        Production costs, including compressor rental, pumpers' salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

        Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

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

F-13

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

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 ASC 740-10-25, which requires the use of 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.

Tax Receivable Agreement

        In conjunction with the IPO, the Company entered into a Tax Receivable Agreement ("TRA") with JEH and the pre-IPO owners. Upon any exchange of JEH—Units and Class B common stock of the Company held by JEH's pre-IPO owners for Class A common stock of the Company, the TRA provides for the payment by the Company, directly to such exchanging owners, of 85% of the amount of cash savings in income or franchise taxes that the Company realizes as a result of (i) the tax basis increases resulting from the exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units for cash) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The Company will retain the benefit of the remaining 15% of the cash savings. Liabilities under the TRA will be recognized upon the exchange of shares. As of December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

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

Statement of Cash Flows

        The Company presents its cash flows using the indirect method.

F-14

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Related Party Transactions

        In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker 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. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the 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 connection with the Company's entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

        JEH implemented a management incentive plan effective January 1, 2010, that provided membership-interest awards in JEH to members of senior management ("management units"). The management unit grants awarded prior to the initial filing of the registration statement in March 2013 had a dual vesting schedule. Sixty percent of the units awarded vested in five equal annual installments, with the remaining 40% vesting upon a company restructuring event, including the IPO. All grants awarded after the initial registration statement have a single vesting structure of five equal annual installments and were valued at the IPO price, adjusted for equivalent shares. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

        Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan, established in conjunction with the Company's IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards. As of December 31, 2013 no such awards had been issued or granted to any of the Company's employees.

F-15

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

        On September 4, 2013, the Company granted each of the four outside members of the Board of Directors 6,645 shares of restricted Class A common stock under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of the restricted stock grants 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 one-year vesting period.

        Refer to Note 7, "Stock-based Compensation," for additional information regarding the management units and restricted stock awards.

Business Combinations

        For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

        The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

        In December 2011, the Financial Accounting Standards Board ("FASB"), issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset arrangement. In January 2013, FASB issued an update to the previously issued guidance with the purpose of clarifying the scope of the disclosures about the offsetting assets and liabilities. The additional disclosures enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity's financial position. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013. The Company has provided all required disclosures for the periods presented as they pertain to its commodity derivative instruments (see Note 4, "Fair Value Measurement"). These disclosure requirements did not affect the Company's operating results, financial position, or cash flows.

3. Acquisition of Properties

        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 an adjusted purchase price of $193.5 million (referred to herein as the "Sabine acquisition" or "Sabine"), subject to customary closing adjustments. The acquired assets include both producing properties and undeveloped

F-16

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

acreage. The purchase was financed with borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved		154,724
Asset retirement obligations		(824	)
Total purchase price	$	193,496

        This acquisition qualified as a business combination under ASC 805. The valuation to determine the fair value was 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 current market. The determination of fair value is dependent on factors as of the acquisition date and the final adjustments to the purchase price, which when they occur, may result in an adjustment to the value of the acquired properties reflected in the consolidated financial statements. Any such adjustment may be material.

        In connection with the closing, approximately $24 million of the purchase price was placed in an escrow account. This amount represented the allocated value of the Sabine properties that had unresolved title defects claimed by JEH. In the event one or more title defects are not cured by Sabine, the affected property will be reconveyed to Sabine and the Company will receive an amount of cash from the escrow account equal to the allocated value of the reconveyed property. A corresponding adjustment to the allocation of the Sabine purchase price will be made at such time.

        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.

        On December 20, 2012, JEH acquired certain oil and natural gas properties located in Texas for a purchase price of $251.9 million (referred to herein as the "Chalker acquisition" or "Chalker"). The acquired assets included both producing properties and undeveloped acreage. The purchase was

F-17

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

financed with additional equity capital and borrowings under the senior secured credit facility. In the second quarter of 2013, the Company made a final determination with the sellers as to the purchase price adjustments resulting in a final purchase price of $253.5 million. The final purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	71,264
Proved		182,493
Asset retirement obligations		(293	)
Total purchase price	$	253,464

        This acquisition qualified as a business combination under ASC 805. The valuation to determine the fair value was 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 current market.

        The unaudited pro forma results presented below have been prepared to include the effect of the Chalker acquisition on our results of operations for the year ended December 31, 2012. 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, 2012 or to project our results of operations for any future date or period.

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses		161,053
Operating income		33,632
Net income		25,713

        On April 14, 2011, Jones Energy acquired certain oil and natural gas properties located in Oklahoma for a purchase price of $154.1 million. The acquisition included both producing and undeveloped properties. The purchase was financed with additional borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations		(167	)
Total purchase price	$	154,058

        This acquisition qualified as a business combination under ASC 805. The Company recorded a total fair value of $180.3 million ($154.1 million for producing properties and $26.2 million for undeveloped property). The total resulted in a bargain purchase gain of $26.2 million, which was recorded in the Consolidated Statement of Operations. The valuation to determine the fair value was

F-18

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

principally based on the discounted cash flows of the both 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 current market. The recognized gain was the difference between the net fair value and the consideration paid the seller.

        Management believes the bargain purchase gain resulted from the fact that the seller, who retained a 50% ownership interest in the undeveloped properties, benefitted from the Company's available liquidity that would enable accelerated development of the prospect.

        The following income statement line items present the pro forma results as if these properties had been acquired on January 1, 2010:

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses		150,197
Operating income		26,687
Net income		62,408

4. 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.

F-19

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

        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.

F-20

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

        The financial instruments carried at fair value as of December 31, 2013 and 2012, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	December 31, 2013
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)			Total
Commodity Price Hedges
Current assets	$	—	$	8,837	$	—		$	8,837
Long-term assets		—		25,967		(569	)		25,398
Current liabilities		—		10,188		476			10,664
Long-term liabilities		—		—		190			190

	December 31, 2012
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	17,648	$	—	$	17,648
Long-term assets		—		24,756		443		25,199
Current liabilities		—		2,992		1,043		4,035
Long-term liabilities		—		6,739		918		7,657

        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, 2013.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 per barrel

        Significant increases/decreases in natural gas liquid futures 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, 2013 and 2012. 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

F-21

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

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 January 1, 2012, net	$	(2,083	)
Purchases		(2,352	)
Settlements		—
Transfers to Level 2		2,370
Transfers to Level 3		834
Changes in fair value		(288	)
Balance at December 31, 2012, net		(1,519	)
Purchases		(1,095	)
Settlements		(210	)
Transfers to Level 2		(753	)
Changes in fair value		2,342
Balance at December 31, 2013, net	$	(1,235	)

        Transfers from Level 3 to Level 2 represent all of the Company's natural gas basis swaps for which observable forward curve pricing information has become readily available. In 2012, transfers to Level 3 represented natural gas liquid swaps or basis swaps that were classified as Level 2 in 2011 but due to the unavailability of forward prices in 2012, were classified as Level 3 in 2012. The purchases represent natural gas liquid swaps that the Company entered into in 2013 that do not have observable forward curve pricing information.

Offsetting Assets and Liabilities

        As of December 31, 2013, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, 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.

F-22

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

        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, 2013 and December 31, 2012:

(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, 2013
Commodity derivative contracts
Assets	$	38,071		$	(6,035	)	$	32,036		$	2,199		$	34,235
Liabilities		(14,347	)		6,035			(8,312	)		(2,542	)		(10,854	)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities		(17,928	)		7,831			(10,097	)		(1,595	)		(11,692	)

Nonfinancial Assets and Liabilities

        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. No significant impairment charges on the Company's proved properties were recorded during the year ended December 31, 2013. During 2012 and 2011, unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, the Company recorded charges of $18.8 million and $19.8 million during the years ended December 31, 2012 and 2011, respectively.

        Additionally, the Company reviews its unproved properties for indicators of impairment based on the Company's current exploration plans. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to the Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage and associated reserves. The Company incurred no impairment charges related to its unproved properties in 2012. In

F-23

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content. With low natural gas prices during that period, the lack of natural gas liquids reduced the economic return of those fields and as a result, the Company had no intentions to continue development of those fields.

        Impairment charges are recorded on the Consolidated Statement of Operations. 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.

5. Derivative Instruments and Hedging Activities

        The Company had various commodity derivatives in place to offset uncertain price fluctuations that could affect its future operations as of December 31, 2013 and 2012, as follows:

Hedging Positions

	December 31, 2013
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.70		$	102.84		$	89.03
	Barrels per month		29,000			161,613			96,149		December 2017
Natural gas swaps	Exercise price	$	3.88		$	6.90		$	4.26
	mmbtu per month		510,000			1,290,000			830,275		December 2017
Basis swaps	Contract differential	$	(0.43	)	$	(0.11	)	$	(0.34	)
	mmbtu per month		320,000			690,000			467,037		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	95.24		$	32.98
	Barrels per month		2,000			118,000			46,646		December 2017

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month		24,000			143,116			89,323		December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month		430,000			1,110,000			767,053		December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month		320,000			850,000			484,615		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month		2,000			144,973			55,616		December 2017

F-24

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

5. Derivative Instruments and Hedging Activities (Continued)

        The Company recognized a net loss on derivative instruments of $2.6 million for the year ended December 31, 2013 and net gains of $16.7 million and $34.5 million for the years ended December 31, 2012 and 2011, respectively.

6. 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") which were subsequently amended on November 18, 2011, November 5, 2012, December 20, 2012, June 12, 2013, December 18, 2013 and January 29, 2014. In connection with the November 2012 amendment, the maturity date of the Revolver was extended to November 5, 2017 and the maturity date of the Term loan was extended to May 5, 2018. In connection with the June 2013 amendment, the borrowing base on the Revolver was increased to $500.0 million and subsequently increased to $575.0 million on December 18, 2013 in conjunction with the Sabine acquisition. The Company's oil and gas properties are pledged as collateral against these credit agreements.

        Terms of the Revolver require the Company to pay interest on the loan on the earlier of the London InterBank Offered Rate (LIBOR) tranche maturity date or three months, with the entire principal and interest due on the loan maturity date. Borrowings may be drawn on the principal amount up to the maximum available credit amount. Interest on the Revolver is calculated at a base rate (LIBOR or prime), plus a margin of 0.50% to 2.50% based on the actual amount borrowed compared to the borrowing base amount and the base rate selected. For the year ended December 31, 2013, the average interest rate under the Revolver was 3.01% on an average outstanding balance of $384.9 million. For the year ended December 31, 2012, the average interest rate under the Revolver was 3.30% on an average outstanding balance of $306.8 million.

        Terms of the Term Loan require the Company to pay interest on the loan every three months with the principal and interest due on the loan maturity date of May 5, 2018. Interest on the Term Loan is calculated at a base rate (LIBOR, prime, or federal funds), plus a margin of 6% to 7% based on the base rate selected. As of December 31, 2013, the average interest rate was 9.19% on an average outstanding balance of $160.0 million. As of December 31, 2012, the average interest rate was 9.16% on an average outstanding balance of $121.3 million.

        Total interest and commitment fees under the two facilities were $27.0 million, $21.2 million and $18.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        In connection with the IPO, the Company used the net proceeds to repay outstanding borrowings under the Revolver of $167.0 million.

        The Revolver and Term Loans are 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 and Term Loans approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

        The Revolver and Term Loans include covenants that require, among other things, restrictions on asset sales, distributions to members, and additional indebtedness, and the maintenance of certain financial ratios, including leverage, proven reserves to debt, and current ratio. The Company was in compliance with these covenants at December 31, 2013.

F-25

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

7. Stock-based Compensation

        JEH granted membership-interest awards in JEH to members of senior management ("management units") under a management incentive plan prior to the IPO. These awards had various vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date. As of December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock. The Units/shares will become convertible into a like number of shares of Class A common stock upon vesting. The following table summarizes information related to the Units/shares held by management:

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		710,767		$	3.62
Granted		911,654		$	15.00
Forfeited		(167,239	)	$	3.62
Vested		(998,032	)	$	9.96
Unvested at December 31, 2013		457,150		$	12.46

        Stock compensation expense associated with the management units for the years ended December 31, 2013, 2012 and 2011 was $10.7 million, $0.6 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

        On September 4, 2013, the Company granted restricted stock awards to non-employee members of the Board of Directors. Each of the four directors was awarded 6,645 restricted shares of Class A common stock, contingent on the director serving as a director of the Company for a one-year service period from the date of grant. The fair value of the awards was based on the value of the Company's Class A common stock on the date of grant. The total value of the awards to the directors is as follows:

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		—		—
Granted		27	$	15.05
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2013		27	$	15.05

        Stock compensation expense associated with the Board of Directors awards for the year ended December 31, 2013 was $0.1 million and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

8. 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. Class B common stock is not included in the calculation of earnings per share

F-26

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

8. Earnings per Share (Continued)

because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. On September 4, 2013 (the "grant date"), the Company granted to its directors restricted shares of Class A common stock, which vest on the first anniversary of the grant date. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. For the year ended December 31, 2013, the directors' restricted shares of Class A common stock were excluded from the diluted calculation, as their inclusion would have been anti-dilutive as the Company was in a net loss position. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the year ended December 31, 2013. Net income (loss) and the weighted average number of shares of Class A common stock outstanding is based on the actual days in which the shares were outstanding for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted		12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock		27

9. Monarch Investment

        On May 7, 2013, the Company entered into a marketing agreement with Monarch Natural Gas, LLC ("Monarch"), a company related through common ownership, for the sale to Monarch of natural gas produced from certain properties. In connection with that agreement, Monarch issued to the Company equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the issuance of the equity interests, the Company distributed 67% or $10 million of the Monarch equity interests to the Company's owners pro rata based on equity contributions and approximately 16% of the interests to a member of management. The remaining approximately 17% of the equity interests were reserved for distribution to management through an incentive plan. The Company recognized $0.3 million of compensation expense during the year ended December 31, 2013 in connection with the incentive plan. In addition, the Company recorded deferred revenue of $15.0 million which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of production sales to Monarch. The Company amortized $0.5 million of the deferred revenue balance during the year ended December 31, 2013 and is recorded in other revenues on the Company's Consolidated Statement of Operations.

F-27

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

10. Commitments and Contingencies

Lease obligations

        The Company leases approximately 31,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for noncancellable operating leases extending beyond one year at December 31, 2013 are as follows:

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015		482
2016		458
2017		147
Thereafter		—
	$	1,673

        Rent expense under operating leases was $0.8 million, $0.8 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, 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.

11. Benefit Plans

        The Company established a 401(k) tax-deferred 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. For the years ended December 31, 2013 and 2012, $0.3 million and $0.2 million were contributed, respectively, to the Plan.

        In 2013, the Company established a 409A tax-deferred savings plan for the benefit of key employees. This plan is a defined contribution plan, and the Company may match a portion of employee contributions. For the year ended December 31, 2013, the Company made a negligible contribution to this plan.

12. Income Taxes

        Following its IPO, the Company began recording a federal and state income tax liability 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

F-28

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

franchise tax expense. The following table summarizes the tax provision for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State		—			—		—
Total current expense		85			—		—
Deferred tax expense (benefit)
Federal		(1,260	)		—		—
State		1,104			473		173
Total deferred expense (benefit)		(156	)		473		173
Total tax expense (benefit)		(71	)		473		173
Tax benefit attributable to controlling interests		(1,223	)		—		—
Tax expense attributable to non-controlling interests		1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

        For the years ended December 31, 2012 and 2011, the reported taxes 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)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate		35	%
Income tax expense computed at statutory rate		7,817
Less: Non-controlling interests		(9,009	)
Income tax benefit attributable to controlling interests		(1,192	)
State and local income taxes, net of federal benefit		(49	)
Other		18
Tax benefit attributable to controlling interests		(1,223	)
Tax expense attributable to non-controlling interests		1,152
Total income tax benefit	$	(71	)

        For the years ended December 31, 2012 and 2011, the calculation is not applicable as the Company was not subject to federal income taxes prior to the IPO.

F-29

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

        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.

        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)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss		649			—
Alternative minimum tax credits		86			—
State deferred tax asset		52			—
Total deferred tax assets		1,313			—
Deferred tax liabilities
State deferred tax liability		3,093			1,936
Total deferred tax liabilities		3,093			1,936
Net deferred tax assets (liabilities)		(1,780	)		(1,936	)
Valuation allowance		—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

        The Company has a federal net operating loss carry-forward totaling $1.8 million and state net operating loss carry-forward of $0.4 million, both expiring in 2033. No valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize its deferred tax assets. This future taxable income will arise from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax basis. The Company may elect to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.

        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 2009, 2010, 2011, and 2012. The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Company is not currently under audit in any other major taxing jurisdiction.

        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, 2013 and December 31, 2012 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-30

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)	2013		2012		2011
Property acquisitions:
Unproved	$	51,266	$	69,725	$	—
Proved		142,230		182,200		168,480
Exploration		1,710		356		780
Development		240,412		125,493		156,628
Asset retirement costs		1,822		662		418
Total costs incurred	$	437,440	$	378,436	$	326,306

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)	2013			2012
Unproved properties	$	114,457		$	137,254
Proved properties		1,568,564			1,127,285
		1,683,021			1,264,539
Accumulated depletion and impairment		(370,470	)		(257,195	)
Net capitalized costs	$	1,312,551		$	1,007,344

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, 2013, 2012 and 2011. 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 economically producible in future years from known oil and natural gas reservoirs under existing

F-31

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, 2010		5,991			9,953			108,634			34,050
Extensions and discoveries		2,419			7,881			50,310			18,685
Production		(811	)		(1,215	)		(11,438	)		(3,932	)
Purchases of minerals in place		378			18,182			117,489			38,142
Sales of minerals in place		(114	)		(201	)		(2,688	)		(763	)
Revisions of previous estimates		(423	)		6			(17,728	)		(3,372	)
December 31, 2011		7,440			34,606			244,579			82,810
Extensions and discoveries		286			1,766			11,727			4,007
Production		(742	)		(1,770	)		(13,980	)		(4,842	)
Purchases of minerals in place		6,056			5,799			36,842			17,995
Sales of minerals in place		(8	)		(53	)		(309	)		(113	)
Revisions of previous estimates		(492	)		(5,602	)		(50,779	)		(14,557	)
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

Revision of previous estimates

        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.

        For the year ended December 31, 2012, the Company had net negative revisions of 14,557 MBoe primarily due to the removal of certain proved undeveloped reserves in the Atoka formation, production performance in the Woodford formation and decreased gas prices in the Cleveland.

        For the year ended December 31, 2011, the Company had net negative revisions of 3,372 MBoe primarily due to the removal of certain proved undeveloped reserves in the Granite Wash, Cleveland, and Atoka formations due to decreased gas prices. This was partially offset by the addition of certain

F-32

proved undeveloped reserves in the more liquid-rich area of the Cleveland formation due to increased oil prices.

	Crude Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBoe)(1)
Estimated Proved Reserves
December 31, 2011
Proved developed		2,535		14,020		110,433		34,961
Proved undeveloped		4,905		20,586		134,146		47,849
Total proved reserves		7,440		34,606		244,579		82,810
December 31, 2012
Proved developed		4,262		16,320		110,956		39,075
Proved undeveloped		8,278		18,426		117,124		46,225
Total proved reserves		12,540		34,746		228,080		85,300
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

(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;

•

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, 2013, 2012 and 2011. 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.

F-33

        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)	2013			2012			2011
Future cash inflows	$	3,213,718		$	2,746,767		$	3,279,260
Less related future:
Production costs		(734,974	)		(612,054	)		(648,035	)
Development costs		(549,343	)		(529,692	)		(556,302	)
Income tax expenses		(129,497	)		—			—
Future net cash flows		1,799,904			1,605,021			2,074,923
10% annual discount for estimated timing of cash flows		(859,395	)		(823,001	)		(1,159,116	)
Standardized measure of discounted future net cash flows	$	940,509		$	782,020		$	915,807

        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)	2013			2012			2011
Balance, beginning of period	$	782,020		$	915,807		$	354,507
Net change in sales and transfer prices, net of production expenses		77,280			(336,855	)		133,740
Changes in estimated future development costs		(9,706	)		67,495			3,391
Sales and transfers of oil and gas produced during the period		(224,739	)		(119,931	)		(139,600	)
Net change due to extensions and discoveries		239,844			37,723			298,299
Net change due to purchases of minerals in place		149,619			197,740			230,687
Net change due to sales of minerals in place		(337	)		(1,578	)		(10,969	)
Net change due to revisions in quantity estimates		(168,438	)		(144,901	)		(48,425	)
Previously estimated development costs incurred during the period		110,783			99,513			83,287
Net change in income taxes		(76,965	)		—			—
Accretion of discount		59,621			91,581			35,451
Other		1,527			(24,574	)		(24,561	)
Balance, end of period	$	940,509		$	782,020		$	915,807

F-34

Supplemental Quarterly Financial Information (Unaudited)

        Following is a summary of the Company's results of operations by quarter for the years ended December 31, 2013 and 2012.

	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 and diluted earnings per share						$	(0.07	)	$	(0.11	)	$	(0.17	)

	2012
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Full Year
Revenues	$	42,797	$	31,354	$	31,935		$	43,728		$	149,814
Operating income (loss)		12,989		1,852		(324	)		(9,677	)		4,840
Net income (loss)		15,323		26,803		(24,527	)		(20,678	)		(3,079	)

Supplemental Quarterly Financial Information (Unaudited)

        We identified an error in our previously issued financial statements which would have been material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period. Therefore, we have revised our Supplemental Quarterly Financial Information for the quarters ended March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013 and September 30, 2013 to reflect additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. These revisions had the effect of:

•

decreasing net income (loss) by $0.1 million, $0.1 million, $0.2 million, $0.2 million, $0.2 million, $0.2 million, and $0.3 million for the quarters ended March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013 and September 30, 2013, respectively;

•

decreasing net income (loss) attributable to non-controlling interests by $0.2 million, for each of the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013; and

•

decreasing net loss attributable to controlling interests by $39 thousand for the quarter ended September 30, 2013.

        We have determined that these errors are not material to any of our previously issued interim or annual consolidated financial statements, therefore, no restatements have been made to the 2013 quarterly financial statements included in our previously filed Form 10-Qs for this matter. Additionally, revisions to the three month period ended March 31, 2013, the three and six month periods ended June 30, 2013 and the three and nine month periods ended September 30, 2013 will be made when they are next filed in the Company's quarterly financial statements on Form 10-Q for the quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, respectively.

F-35

EX-2.2

Exhibit 2.2

EXECUTION VERSION

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

TABLE OF CONTENTS

		Page
ARTICLE 1 DEFINITIONS AND INTERPRETATION		1
Section 1.1	Defined Terms	1
Section 1.2	References and Rules of Construction	1
ARTICLE 2 PURCHASE AND SALE		2
Section 2.1	Purchase and Sale	2
Section 2.2	Assets	2
Section 2.3	Excluded Assets	3
Section 2.4	Effective Time; Proration of Costs and Revenues	3
Section 2.5	Procedures	4
ARTICLE 3 PURCHASE PRICE		5
Section 3.1	Purchase Price	5
Section 3.2	Allocation of Purchase Price	5
Section 3.3	Adjustments to Purchase Price	6
Section 3.4	Allocated Values	8
Section 3.5	Parent Guaranties	8
ARTICLE 4 TITLE AND ENVIRONMENTAL MATTERS		8
Section 4.1	Seller’s Title	8
Section 4.2	Title Defects	9
Section 4.3	Title Benefits	13
Section 4.4	Title Disputes	14
Section 4.5	Limitations	15
Section 4.6	Consents to Assignment and Preferential Rights to Purchase	17
Section 4.7	Casualty or Condemnation Loss	19
ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF SELLER		19
Section 5.1	Generally	19
Section 5.2	Existence and Qualification	20
Section 5.3	Power	20
Section 5.4	Authorization and Enforceability	20
Section 5.5	No Conflicts	20
Section 5.6	Liability for Brokers’ Fees	20
Section 5.7	Litigation	20
Section 5.8	Consents and Preferential Purchase Rights	20
Section 5.9	Non-Consent Operations	21
Section 5.10	Taxes and Assessments	21
Section 5.11	Capital Commitments	22
Section 5.12	Contracts	22

i

TABLE OF CONTENTS

		Page
Section 5.13	Wells and Equipment	22
Section 5.14	Environmental Matters	23
Section 5.15	Bankruptcy	23
Section 5.16	Permits	24
Section 5.17	Payments for Production; Imbalances	24
Section 5.18	Suspended Proceeds	24
Section 5.19	Leases	24
Section 5.20	Availability of Properties	24
Section 5.21	Certain Disclaimers	24
ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER		26
Section 6.1	Existence and Qualification	26
Section 6.2	Power	26
Section 6.3	Authorization and Enforceability	26
Section 6.4	No Conflicts	26
Section 6.5	Liability for Brokers’ Fees	26
Section 6.6	Litigation	27
Section 6.7	Financing	27
Section 6.8	Securities Law Compliance	27
Section 6.9	Independent Evaluation	27
Section 6.10	Consents, Approvals or Waivers	27
Section 6.11	Bankruptcy	27
Section 6.12	Qualification	27
Section 6.13	Limitation	27
ARTICLE 7 COVENANTS OF THE PARTIES		28
Section 7.1	Access	28
Section 7.2	Government Reviews	30
Section 7.3	Public Announcements; Confidentiality	30
Section 7.4	Operation of Business	31
Section 7.5	Operatorship	33
Section 7.6	Change of Name	33
Section 7.7	Replacement of Insurance, Bonds, Letters of Credit and Guaranties	33
Section 7.8	Notification of Breaches	33
Section 7.9	Amendment to Schedules	34
Section 7.10	Release of Liens	34
Section 7.11	Hedges	34
Section 7.12	Further Assurances	34
Section 7.13	Financial Statements	34
ARTICLE 8 CONDITIONS TO CLOSING		35
Section 8.1	Seller’s Conditions to Closing	35
Section 8.2	Purchaser’s Conditions to Closing	35

ii

TABLE OF CONTENTS

		Page
ARTICLE 9 CLOSING		36
Section 9.1	Time and Place of Closing	36
Section 9.2	Obligations of Seller at Closing	37
Section 9.3	Obligations of Purchaser at Closing	37
Section 9.4	Closing Payment and Post-Closing Purchase Price Adjustments	38
ARTICLE 10 TERMINATION		39
Section 10.1	Termination	39
Section 10.2	Effect of Termination	40
Section 10.3	Distribution of Deposit Upon Termination	40
Section 10.4	Purchaser Hedges	40
ARTICLE 11 ASSUMPTION; INDEMNIFICATION		41
Section 11.1	Assumption by Purchaser, Retention by Seller	41
Section 11.2	Indemnification	42
Section 11.3	Indemnification Actions	44
Section 11.4	Limitation on Actions	45
ARTICLE 12 TAX MATTERS		47
Section 12.1	Tax Filings	47
Section 12.2	Current Tax Period Taxes	47
Section 12.3	Tax Reimbursement	48
Section 12.4	Characterization of Certain Payments	48
Section 12.5	Tax-Deferred Exchange	48
ARTICLE 13 MISCELLANEOUS		49
Section 13.1	Counterparts	49
Section 13.2	Notice	49
Section 13.3	Tax, Recording Fees, Similar Taxes & Fees	50
Section 13.4	Governing Law; Jurisdiction	50
Section 13.5	Waivers	51
Section 13.6	Assignment	51
Section 13.7	Entire Agreement	51
Section 13.8	Amendment	51
Section 13.9	No Third Party Beneficiaries	51
Section 13.10	Construction	51
Section 13.11	Limitation on Damages	52
Section 13.12	Recording	52
Section 13.13	Conspicuous	52
Section 13.14	Time of Essence	52
Section 13.15	Delivery of Records	52

iii

TABLE OF CONTENTS

		Page
Section 13.16	Severability	53
Section 13.17	Specific Performance	53

APPENDICES:
Appendix A	-	Definitions
EXHIBITS:
Exhibit A-1	-	Leases
Exhibit A-2	-	Wells and Undeveloped Properties
Exhibit A-3	-	Surface Interests
Exhibit A-4	-	Certain Excluded Assets
Exhibit B	-	Form of Conveyance
Exhibit C	-	Form of Purchaser Parent Guaranty
Exhibit D	-	Form of Letter-in-lieu of Transfer Order
Exhibit E	-	Form of Seller Parent Guaranty
Exhibit F	-	Form of Escrow Agreement
SCHEDULES:
Schedule 3.4	-	Allocated Values
Schedule 5.1	-	Seller Knowledge Individuals
Schedule 5.7	-	Litigation
Schedule 5.8	-	Consents and Preferential Purchase Rights
Schedule 5.9	-	Non-Consent Operations
Schedule 5.11	-	Capital Commitments
Schedule 5.12	-	Contracts
Schedule 5.13	-	Wells and Equipment
Schedule 5.16	-	Permits
Schedule 5.17	-	Imbalances
Schedule 5.18	-	Suspended Proceeds
Schedule 5.19	-	Leases
Schedule 6.6	-	Purchaser Knowledge Individuals
Schedule 7.4	-	Operations
Schedule 10.4	-	Purchaser Hedges
Schedule 11.1	-	Assumed Purchaser Obligations
Schedule 11.2(b)(vii)	-	Retained Seller Litigation

iv

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (as may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is dated as of November 22, 2013 (the “Execution Date”), by and between Sabine Mid-Continent LLC, a Delaware limited liability company (“Seller”), on the one part, and Jones Energy Holdings, LLC, a Delaware limited liability company (“Purchaser”), on the other part.  Seller and Purchaser are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS:

A.Seller owns certain interests in oil and gas properties, rights and related assets that are defined and described herein as the “Assets.”

B.Seller desires to sell to Purchaser and Purchaser desires to purchase from Seller the Assets, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1
DEFINITIONS AND INTERPRETATION

Section 1.1Defined Terms.  In addition to the terms defined in the introductory paragraph and the Recitals of this Agreement, for purposes hereof, the capitalized terms used herein and not otherwise defined shall have the meanings set forth in Appendix A.

Section 1.2References and Rules of Construction.  All references in this Agreement to Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions refer to the corresponding Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions of or to this Agreement unless expressly provided otherwise.  Titles appearing at the beginning of any Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement and shall be disregarded in construing the language hereof.  The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection, clause or other subdivision unless expressly so limited.  The words “this Article,” “this Section,” “this subsection,” “this clause,” and words of similar import, refer only to the Article, Section, subsection and clause hereof in which such words occur.  The word “including” (in its various forms) means including without limitation.  All references to “$” shall be deemed references to Dollars.  Each accounting term not defined herein will have the meaning given to it under GAAP as interpreted as of the Execution Date.   Unless expressly provided to the contrary, the word “or” is not exclusive.  Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires.  Appendices, Exhibits and Schedules referred to herein are

attached to and by this reference incorporated herein for all purposes.  References to (a) any Law, agreement or contract means such Law, agreement or contract, as applicable, as it may be amended from time to time and (b) any date shall mean such date in Houston, Texas and for purposes of calculating the time period in which any notice or action is to be given or taken hereunder, such period shall be deemed to begin at 12:01 a.m. on the applicable date in Houston, Texas.

ARTICLE 2
PURCHASE AND SALE

Section 2.1Purchase and Sale.  At the Closing, upon the terms and subject to the conditions of this Agreement, Seller agrees to sell, transfer and convey the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets and to assume the Assumed Purchaser Obligations.

Section 2.2Assets.  As used herein, the term “Assets” means, subject to the terms and conditions of this Agreement, all of Seller’s right, title and interest in and to the following (but excepting and excluding, in all such instances, the Excluded Assets):

(a)The oil and gas leases, oil, gas and mineral leases, subleases and other leaseholds, royalties, overriding royalties, net profits interests, mineral fee interests, carried interests, and other rights to Hydrocarbons in place that are identified on Exhibit A-1 (collectively, the “Leases”) together with all other rights in the lands covered by the Leases, subject to the depth limitations and other restrictions that may be set forth in the Leases;

(b)All pooled, communitized or unitized acreage which includes all or a part of the lands covered by the Leases (the “Units”), and all tenements, hereditaments and appurtenances belonging thereto;

(c)Any and all Hydrocarbon, water, carbon dioxide, or injection wells used or held for use in connection with the development of the Leases and located on the lands covered by the Leases or any Units, whether producing, shut-in or temporarily abandoned, including the interests in the wells shown on Exhibit A-2 (the “Wells”; and together with the Units and Leases, the “Properties”);

(d)All currently existing contracts, agreements and instruments to the extent applicable to the Properties or the production of Hydrocarbons from the Properties, including operating agreements, unitization, pooling and communitization agreements, declarations and orders, area of mutual interest agreements, joint venture agreements, farmin and farmout agreements, participation agreements, exchange agreements, transportation agreements, agreements for the sale and purchase of Hydrocarbons, processing agreements, and confidentiality agreements related to Seller’s disposition of the Assets, but excluding (i) any contracts, agreements and instruments for which the necessary consents to transfer are not obtained pursuant to Section 4.6, (ii) instruments constituting Seller’s chain of title to the Leases, (iii) the Leases and (iii) master service agreements (subject to such exclusions, the “Contracts”);

(e)All surface fee interests, easements, permits, licenses, servitudes, rights-of-way, surface leases and other surface rights appurtenant to, and used or held for use solely in

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connection with, the Properties, including those interests set forth on Exhibit A-3; but excluding, in all such instances, any permits and other appurtenances for which the necessary consents to transfer are not obtained pursuant to Section 4.6;

(f)All equipment, machinery, tools, fixtures, pipelines, flowlines, gathering lines and other tangible personal property (excepting and reserving any Hydrocarbons stored in stock tanks, pipelines or other storage as of the Effective Time) and improvements primarily used or held for use in connection with the operation of the Properties or the production, storage, transportation, treatment, processing, marketing or disposition of Hydrocarbons from the Properties (whether located on or off the Properties) (the “Equipment”);

(g)All Hydrocarbons produced from or attributable to the Leases, Units or Wells at and after the Effective Time and all Hydrocarbon inventories from or attributable to the Properties that are in storage on the Effective Time;

(h)All rights of Seller to audit the records of any Person and to receive refunds or payments of any nature, and all amounts of money relating thereto, whether before, on or after the Effective Time, to the extent relating to obligations assumed by Purchaser pursuant to this Agreement;

(i)The Records; and

(j)The Leased Assets, except to the extent that any of the Leased Assets are transferable with the payment of a fee or other consideration (unless Purchaser has agreed in writing to pay such fee or other consideration).

Section 2.3Excluded Assets.  Notwithstanding anything to the contrary, the Assets shall not include, and there is excepted, reserved and excluded from this transaction, the Excluded Assets.

Section 2.4Effective Time; Proration of Costs and Revenues.

(a)Subject to the other terms and conditions of this Agreement, possession of the Assets shall be transferred from Seller to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be transferred effective as of 7:00 a.m., Central Time, on October 1, 2013 (the “Effective Time”), as described below.

(b)Purchaser shall be entitled to all production of Hydrocarbons from or attributable to the Leases, Units and Wells at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at and after the Effective Time (provided that, notwithstanding the preceding, Seller shall be entitled to all proceeds of cash calls and billings and other funds received for the account of Third Parties with respect to any of the Assets operated by Seller for all periods prior to the date on which Seller’s resignation as operator of such Assets becomes effective), and shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred at and after the Effective Time.

(c)Seller shall be entitled to all production of Hydrocarbons from or

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attributable to Leases, Units and Wells prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time (and to proceeds from cash calls and billings and other funds received for the account of Third Parties for all periods prior to the date on which Seller’s resignation as operator becomes effective, as described in clause (b) above), and shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred prior to the Effective Time.

(d)Should Purchaser receive after Closing any proceeds or other income to which Seller is entitled under Section 2.4(c), Purchaser shall fully disclose, account for and remit same within ten (10) days to Seller.  If, after Closing, Seller receives any proceeds or other income with respect to the Assets to which Purchaser is entitled pursuant to Section 2.4(b), Seller shall fully disclose, account for and remit same within ten (10) days to Purchaser.

(e)Should Purchaser pay after Closing any Property Costs for which Seller is responsible under Section 2.4(c), Seller shall reimburse Purchaser within ten (10) days after receipt of an invoice with respect to such Property Costs, accompanied by copies of the relevant vendor or other invoice or Tax Return and proof of payment.  Should Seller pay after Closing any Property Costs for which Purchaser is responsible under Section 2.4(b), Purchaser shall reimburse Seller within ten (10) days after receipt of an invoice with respect to such Property Costs, accompanied by copies of the relevant vendor or other invoice or Tax Return and proof of payment.

(f)Consistent with Section 12.2 (as applicable), Asset Taxes that are included in Property Costs, right-of-way fees, insurance premiums and other Property Costs that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at and after the Effective Time, except that ad valorem, production, severance and similar Taxes measured by the quantity of or the value of production shall be prorated based on the number of units or value of production actually produced and sold, as applicable, before the Effective Time, and at or after the Effective Time.  Notwithstanding any other provision in this Agreement, Purchaser shall be responsible for the portion allocated to the period at and after the Effective Time and Seller shall be responsible for the portion allocated to the period before the Effective Time.

Section 2.5Procedures.

(a)For purposes of allocating production (and accounts receivable with respect thereto) under Section 2.4  and Section 3.3, as applicable, (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Units and Wells when they pass through the inlet flange of the pipeline connecting into the storage facilities into which they are run or, if there are no such storage facilities, when they pass through the LACT meters or similar meters at the point of entry into the pipelines through which they are transported from the field and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Units and Wells when they pass through the delivery point sales meters on the pipelines through which they are transported.  Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings or gauging and strapping data is not available.  Upon request, Seller shall provide to Purchaser evidence of all meter readings and all

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gauging and strapping procedures conducted on or about the Effective Time in connection with the Assets, together with all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the Unadjusted Purchase Price pursuant to Section 3.3.  The terms “earned” and “incurred” shall be interpreted in accordance with generally accepted accounting principles and Council of Petroleum Accountants Society (“COPAS”) standards, and expenditures which are incurred pursuant to an operating agreement, unit agreement or similar agreement shall be deemed incurred when expended by the operator of the applicable Lease, Unit or Well, in accordance with Seller’s current practice.

(b)After Closing, each Party shall handle all joint interest audits and other audits of Property Costs covering the period for which such Party is in whole or in part responsible under Section 2.4, provided that the other Party (i) shall provide reasonable assistance in connection with any such an audit if so requested by the auditing Party and (ii) shall be entitled to participate in any such audit to the extent relating to periods for which such other Party is partially responsible.

ARTICLE 3
PURCHASE PRICE

Section 3.1Purchase Price.  The purchase price for the Assets (the “Purchase Price”) shall be One Hundred Ninety-Five Million Dollars ($195,000,000.00), (the “Unadjusted Purchase Price”).  The Unadjusted Purchase Price shall be adjusted as provided in Section 3.3, and the determination of the Adjusted Purchase Price shall be made as provided in Section 9.4.  Upon the execution of this Agreement, Purchaser shall deliver to Seller an amount equal to five percent (5%) of the Unadjusted Purchase Price (the “Deposit”).  The Deposit shall be retained by Seller (and taken into account in the determination of the Closing Payment pursuant to Section 9.4(a)) if the Closing occurs or shall be otherwise distributed in accordance with the terms of Section 10.3.

Section 3.2Allocation of Purchase Price.  The Parties agree that the Adjusted Purchase Price and any liabilities associated with the Assets (to the extent properly taken into account under the Code) shall be allocated among the Assets for Tax purposes (including Section 1060 of the Code and the Treasury Regulations thereunder) in accordance with an allocation schedule that shall be prepared by Purchaser and delivered to Seller for Seller’s review, comment and consent within ten (10) days following the final determination of the Adjusted Purchase Price (as revised under this Section 3.2, the “Purchase Price Allocation Schedule”). The Purchase Price Allocation Schedule shall be revised to take into account adjustments to the Unadjusted Purchase Price and any indemnification payments.  If the Parties are unable to agree on the Purchase Price Allocation Schedule or any revisions thereto, any dispute arising in connection with the Purchase Price Allocation Schedule shall be resolved pursuant to procedures comparable to the procedures applicable under Section 9.4(b).  The Parties shall use the Purchase Price Allocation Schedule in reporting this transaction to the applicable Taxing authorities, including IRS Form 8594 and any other Tax Returns and supplement thereto required to be filed under Section 1060 of the Code, and neither Party shall file any Tax Return or otherwise take any position for Tax purposes that is inconsistent with the Purchase Price Allocation Schedule, except as required by applicable Law.  Each Party shall promptly notify the other Party in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging

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the Purchase Price Allocation Schedule, and neither Party shall agree to any proposed adjustment to the allocation contained in the Purchase Price Allocation Schedule by any Taxing authority without first giving to the other Party prior written notice.  However, nothing contained herein shall prevent either Party from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the Purchase Price Allocation Schedule and neither Party shall be required to litigate any proposed deficiency or adjustment by any Taxing authority challenging such Purchase Price Allocation Schedule.

Section 3.3Adjustments to Purchase Price.  All adjustments to the Unadjusted Purchase Price shall be made (x) in accordance with the terms of this Agreement and, to the extent not inconsistent with this Agreement, in accordance with GAAP as consistently applied by Seller in its accounting of and for the Assets (as of the Effective Time), (y) without duplication (in this Agreement or otherwise) and (z) only with respect to matters (A) in the case of Section 3.3(b)(iii), for which notice is given on or before the Title Claim Date, and (B) in all of the other cases set forth in Section 3.3(a) and Section 3.3(b), identified on or before the Cut-off Date. Each adjustment to the Unadjusted Purchase Price described in Section 3.3(a) and Section 3.3(b) shall be allocated among the Assets in accordance with Section 3.4.

Without limiting the foregoing, the Unadjusted Purchase Price shall be adjusted as follows, with the resulting adjustments to such Unadjusted Purchase Price herein the “Adjusted Purchase Price”:

(a)The Unadjusted Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)an amount equal to all Property Costs and other costs (including, for the avoidance of doubt, all Asset Taxes) attributable to the ownership and operation of the Assets which are incurred at and after the Effective Time but paid by Seller (as is consistent with Section 2.4(b) and Section 2.4(c)), but excluding any amounts previously reimbursed to Seller pursuant to Section 2.4(e);

(ii)an amount equal to, to the extent that such amounts have been received by Purchaser and not remitted or paid to Seller, (A) all proceeds from the production of Hydrocarbons from or attributable to the Leases, Units and Wells prior to the Effective Time, (B) all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time (including proceeds from cash calls and billings and other funds received for the account of Third Parties with respect to any of the Assets operated by Seller for all periods prior to the date on which Seller’s resignation as operator becomes effective) and (C) any other amounts to which Seller is entitled pursuant to Section 2.4(c);

(iii)the amount of all prepaid expenses (including pre-paid bonuses, rentals, cash calls and advances to Third Party operators for expenses not yet incurred; prepaid production Taxes, severance Taxes and other Taxes; and scheduled payments) paid by Seller with respect to the ownership or operation of the Assets at and after the Effective Time;

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(iv)to the extent that proceeds for such volumes have not been received by Seller, an amount equal to the aggregated volumes of Hydrocarbons stored in stock tanks, pipelines or other storage (excluding Tank Bottom Hydrocarbons) as of the Effective Time from or attributable to the ownership and operation of the Assets multiplied by the contract price therefor on the Effective Time;

(v)to the extent that Seller is underproduced as of the Effective Time, as shown with respect to the net Imbalances on Schedule 5.17, as complete and final settlement of all such Imbalances, the amount of the net Imbalances multiplied by a price of $3.56 per MMBtu; and

(vi)any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by the Parties as an upward adjustment to the Unadjusted Purchase Price.

(b)The Unadjusted Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)an amount equal to all Property Costs and other costs (including, for the avoidance of doubt, all Asset Taxes) attributable to the ownership and operation of the Assets which are incurred prior to the Effective Time but paid by Purchaser (as is consistent with Section 2.4(b) and Section 2.4(c)), but excluding any amounts previously reimbursed to Purchaser pursuant to Section 2.4(e);

(ii)an amount equal to, to the extent that such amounts have been received by Seller and not remitted or paid to Purchaser, (A) all proceeds from the production of Hydrocarbons from or attributable to the Leases, Units and Wells at and after the Effective Time, (B) all other income, proceeds, receipts and credits earned with respect to the Assets at and after the Effective Time (excluding all proceeds of cash calls and billings and other funds received for the account of Third Parties with respect to any of the Assets operated by Seller for all periods prior to the date on which Seller’s resignation as operator of such Assets becomes effective) and (C) any other amounts to which Purchaser is entitled pursuant to Section 2.4(b);

(iii)except for those amounts described in Section 3.3(b)(iv), Section 3.3(b)(v) and Section 3.3(b)(xi), as applicable, any amounts for Title Defects determined pursuant to Section 4.2 (which shall include, for purposes of certainty, an amount equal to the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.2(c)), offset by any Title Benefit Amounts determined pursuant to Section 4.3;

(iv)an amount equal to all Title Defect Amounts placed into the Escrow Account pursuant to Section 4.2;

(v)an amount equal to the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.2(h);

(vi)an amount equal to the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.6;

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(vii)an amount equal to the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.7;

(viii)an amount equal to the Allocated Value of any Assets excluded from this transaction pursuant to Section 7.1(b);

(ix)to the extent that Seller is overproduced as of the Effective Time as shown with respect to the net Imbalances on Schedule 5.17, as complete and final settlement of all such Imbalances, the amount of the net Imbalances multiplied by a price of $3.56 per MMBtu;

(x)the amount of the Suspense Funds;

(xi)the amount of the Unescrowed Amount;

(xii)any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by the Parties as a downward adjustment to the Unadjusted Purchase Price.

Section 3.4Allocated Values.  The “Allocated Values” for the Assets are set forth on Schedule 3.4.  The Allocated Value for an Asset is equal to the portion of the Unadjusted Purchase Price that is allocated to such Asset on Schedule 3.4, increased or decreased by a share of each adjustment to the Unadjusted Purchase Price in accordance with Section 3.3.  Except with respect to Section 3.3(a)(vi) and Section 3.3(b)(xii), the share of each adjustment allocated to a particular Asset shall be allocated to the particular Asset to which such adjustment relates to the extent such adjustment relates to such Asset and to the extent that it is, in the commercially reasonable discretion of Seller, possible to do so.  Adjustments made pursuant to Section 3.3(a)(vi) and Section 3.3(b)(xii) and any adjustment not allocated to a specific Asset pursuant to the immediately preceding sentence shall be allocated among the various Assets on a pro-rata basis in proportion to the Unadjusted Purchase Price allocated to such Asset on Schedule 3.4. Seller has accepted such Allocated Values for purposes of this Agreement and the transactions contemplated hereby, but makes no representation or warranty as to the accuracy of such values.

Section 3.5Parent Guaranties.  Simultaneously with the execution of this Agreement, (a) Purchaser has caused Purchaser Parent Company to deliver to Seller the Purchaser Parent Guaranty and (b) Seller has caused Sabine Parent to deliver to Purchaser the Seller Parent Guaranty.

ARTICLE 4
TITLE AND ENVIRONMENTAL MATTERS

Section 4.1Seller’s Title.  Except for the special warranty of title set forth in the Conveyance, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets and Purchaser hereby acknowledges and agrees that, subject to Section 4.5, Purchaser’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets, (a) on or before the applicable Title Claim Date, shall be as set forth in Section 4.2 and, (b) subject to the following sentence, from and after the applicable Title Claim Date (without duplication), shall be pursuant to the special warranty of

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title set forth in the Conveyance.  Purchaser further acknowledges and agrees that Purchaser shall not be entitled to protection under (nor have the right to make a claim against) the special warranty of title provided in the Conveyance for (i) any Title Defect reported under this Article 4 and (ii) any Excluded Defect.

Section 4.2Title Defects.

(a)To assert a claim of a Title Defect, Purchaser must deliver a claim notice to Seller (each a “Title Defect Notice”) promptly after the discovery thereof, but in no event later than 11:59 p.m., Central Time, on December 13, 2013 (such cut-off date being the “Title Claim Date”).  To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect that is reasonably sufficient for Seller to determine the basis of the alleged Title Defect, (ii) the Property or Properties adversely affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv)  documents upon which Purchaser relies for its assertion of a Title Defect, including supporting documents reasonably necessary for Seller to verify the existence of the alleged Title Defect, and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect or, in the case of an Environmental Defect, the amount which Purchaser reasonably believes is required to correct, remediate or resolve the alleged Environmental Defect, and the computations and information upon which Purchaser’s belief is based. Notwithstanding anything herein to the contrary, Purchaser forever waives Title Defects not asserted by a Title Defect Notice meeting all of the requirements set forth in the preceding sentence by 11:59 p.m., Central Time, on the Title Claim Date.

(b)Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure or remove on or before the date that is sixty (60) days after the Closing Date (the “Cure Period”) any Title Defect for which Seller has received a Title Defect Notice from Purchaser prior to or on the Title Claim Date.  No downward adjustment shall be made to the Unadjusted Purchase Price with respect to a Title Defect which Seller has cured prior to the Closing Date.  If a Title Defect is not cured prior to the Closing Date, the provisions of Section 4.2(c) and Section 4.2(d), as applicable, shall apply to such uncured Title Defect.

(c)In the event that a Title Defect for which Seller has not delivered a cure notice pursuant to Section 4.2(d) is not waived by Purchaser or cured prior to the Closing Date, Seller shall, at its sole election, and subject to Section 4.5(b), on or before Closing elect to (i) make a downward adjustment to the Unadjusted Purchase Price equal to the Title Defect Amount of such Title Defect, (ii) retain the entirety of the Title Defect Property that is adversely affected by such Title Defect, in which event, the Unadjusted Purchase Price shall be adjusted downward by an amount equal to the Allocated Value of such Title Defect Property and such Title Defect Property shall no longer be included within the definition of Assets for any purpose under this Agreement or (iii) submit any Title Disputed Matter with respect to such Title Defect for resolution pursuant Section 4.4, in which event, (A) the Title Defect Amount (as reasonably estimated by Purchaser for purposes of Closing) relating to the Disputed Title Matter shall be deposited into the Escrow Account in accordance with the terms of this Agreement and the Escrow Agreement, (B) the relevant Title Defect Property shall be conveyed to Purchaser at Closing and (C) the Unadjusted Purchase Price shall be adjusted downward pursuant to Section 3.3(b)(iv) by such Title Defect Amount.

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(d)If Seller is unable to cure a Title Defect on or prior to the Closing Date, Seller shall have the option, by notice in writing to Purchaser on or before Closing, to attempt to cure such Title Defect on or before the termination of the Cure Period and at Closing to reduce the Purchase Price pursuant to Section 3.3(b)(iv) by the Title Defect Amount (as reasonably estimated by Purchaser for purposes of Closing) with respect to such Title Defect and, if Seller so elects, such Title Defect Amount shall be deposited into an escrow account established with the Escrow Agent (the “Escrow Account”) to be held and disbursed in accordance with the terms of this Agreement and an escrow agreement in substantially the form attached hereto as Exhibit F (the “Escrow Agreement”).  The applicable Title Defect Property shall be conveyed to Purchaser at Closing, and Purchaser will not take such actions during the Cure Period that adversely affects or otherwise impairs the ability of Seller to remedy the Title Defect for such Title Defect Property.  An election by Seller to attempt to cure a Title Defect shall be without prejudice to its rights under Section 4.4 and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect.

(e)Notwithstanding anything to the contrary contained herein, no amounts in excess of fifteen percent (15%) of the Unadjusted Purchase Price shall be deposited into the Escrow Account pursuant to Section 4.2(c)(iii) and Section 4.2(d).  Accordingly, in the event that the aggregate Title Defect Amounts (as reasonably estimated by Purchaser) for all Title Defects which are disputed pursuant to Section 4.2(c)(iii) or which Seller elects to cure pursuant to Section 4.2(d) but which remain uncured on the Closing Date exceed fifteen percent (15%) of the Unadjusted Purchase Price (the amount of such excess the “Unescrowed Amount”), then (i) the Unadjusted Purchase Price shall be adjusted downward pursuant to Section 3.3(b) by the Unescrowed Amount and (ii) the relevant Title Defect Properties shall be conveyed to Purchaser at Closing.  Notwithstanding any Unescrowed Amount, Disputed Title Matters and Title Defects which Seller has elected to cure shall first be satisfied from the Escrow Amount pursuant to Section 4.2(f).   Once the Escrow Amount is exhausted, except as otherwise taken into account or otherwise addressed in Section 4.2(f)(i) and Section 4.2(f)(iii), as applicable, amounts owed to Seller under this Section 4.2 shall be accounted for in the final determination of the Purchase Price pursuant to Section 9.4(b).

(f)Subject to Section 4.4 and Section 4.5(b), as applicable, the Escrow Amount and the Unescrowed Amount, as applicable, shall be distributed and paid, as and if applicable, in accordance with the following:

(i)The Parties shall promptly instruct the Escrow Agent to release to Seller the Title Defect Amount (together with any interest earned thereon) held in the Escrow Account with respect to a Title Defect that is cured as agreed by the Parties prior to the termination of the Cure Period or, in the case that the cure thereof is a Disputed Title Matter, determined to be cured pursuant to Section 4.4.  In the event that the remaining funds in the Escrow Account are less than such Title Defect Amount (or if no funds remain in the Escrow Account at such time), then Purchaser will pay  to Seller the unfunded portion of such amount within ten (10) days of such Title Defect being cured or determined to be cured pursuant to Section 4.4, as applicable.

(ii)The Parties shall promptly instruct the Escrow Agent to release to

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Purchaser the Title Defect Amount (together with any interest thereon) (the “Failed Cure Amount”) held in the Escrow Account with respect to a Title Defect that is not cured as agreed by the Parties or, in the case that the cure thereof is a Disputed Title Matter, that is determined pursuant to Section 4.4 to have not been cured at the end of the Cure Period.  In such event, (A) the Parties shall instruct the Escrow Agent to release to Purchaser the Failed Cure Amount and, (B) if Seller so elects, the Purchase Price shall be reduced by the difference between the Allocated Value of the Property affected by such Title Defect minus the Failed Cure Amount returned to Purchaser (which shall be taken into account in the final determination of the Purchase Price pursuant to Section 9.4(b)), in which event, Purchaser shall reconvey the Property affected by such Title Defect to Seller, which shall be deemed an Excluded Asset under this Agreement.

(iii)With respect to any Disputed Title Matters that are not addressed under clauses (i) and (ii) above, the Parties shall promptly instruct the Escrow Agent to release to the appropriate Party (based on the Arbitration Decision) the Title Defect Amount (together with any interest thereon) (the “Resolved Defect Amount”) from the Escrow Account with respect to such Disputed Title Matter following the rendering of the Arbitration Decision pursuant to Section 4.4.  In the event that the Resolved Defect Amount is released to Purchaser pursuant to the preceding sentence, Seller may elect to cause the Purchase Price to be reduced by the difference between the Allocated Value of the Property affected by the Disputed Title Matter minus the Resolved Defect Amount returned to Purchaser (which shall be taken into account in the final determination of the Purchase Price pursuant to Section 9.4(b)), in which event, Purchaser shall reconvey the Property affected by such Disputed Title Matter to Seller, which shall be deemed an Excluded Asset under this Agreement.  In the event that the remaining funds in the Escrow Account are less than the portion of the Resolved Defect Amount owed to Seller (or if no funds remain in the Escrow Account at such time), if any, then Purchaser will pay to Seller the unfunded portion of the Resolved Defect Amount owed to Seller within ten (10) days of the rendering of the Arbitration Decision pursuant to Section 4.4.

(g)The “Title Defect Amount” resulting from a Title Defect other than (i) an Environmental Defect and (ii) Title Defect Amounts determined pursuant to Section 4.2(g)(ii), shall be the amount by which the Allocated Value of the Title Defect Property adversely affected by such Title Defect is reduced as a result of the existence of such Title Defect.  The Title Defect Amount shall be determined in accordance with the following methodology, terms and conditions:

(i)if Purchaser and Seller agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii)if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from Seller’s (and Purchaser’s, as successor in interest to Seller) interest in the affected Title Defect Property;

(iii)if the Title Defect reflects a discrepancy (with a proportionate decrease in the Working Interest for the affected Title Defect Property) between (A) the

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Net Revenue Interest for the affected Title Defect Property and (B) the Net Revenue Interest stated in Exhibit A-2, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the amount of the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated in Exhibit A-2;

(iv)if the Title Defect is an Environmental Defect, the Title Defect Amount shall be the amount of the estimated costs and expenses to correct, remediate or resolve the Environmental Defect (as of the Closing Date) in such a manner that satisfies applicable Environmental Laws;

(v)if the Title Defect represents an obligation, encumbrance, burden or charge upon or other defect in title to the Title Defect Property of a type not described in clauses (ii), (iii) or (iv) above (including any increase in Working Interest for which there is not a proportionate increase in Net Revenue Interest), the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property adversely affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Purchaser and Seller and such other factors as are necessary to make a proper evaluation; provided, however, that the foregoing considerations notwithstanding, in the event that the Title Defect is reasonably susceptible of being cured, the Title Defect Amount shall not be greater than the reasonable cost and expense of curing or remediating, as applicable, such Title Defect;

(vi)the Title Defect Amount with respect to a Title Defect shall be determined without duplication of any costs or losses included in any other Title Defect Amount hereunder, or for which Purchaser otherwise receives credit in the calculation of the Purchase Price; and

(vii)notwithstanding anything to the contrary in this Article 4, except with respect to Environmental Defects and Title Defect Amounts determined pursuant to Section 4.2(g)(ii), the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(h)It is understood and agreed that Environmental Defects shall constitute Title Defects for purposes of this Agreement and, as such, will be handled in accordance with, and in all instances will be subject to, the provisions of this Section 4.2 and the other applicable provisions of this Article 4 (including the thresholds and deductibles set forth in Section 4.5).   As such, without limiting the disclaimers and acknowledgements set forth in Article 5 and Article 6, respectively, and without prejudice to any rights of Purchaser arising under Section 11.2(b), including as a result of the breach of Section 5.14, PURCHASER HEREBY WAIVES AND RELEASES ANY REMEDIES OR CLAIMS (WHETHER AT LAW OR IN EQUITY) THAT IT MAY HAVE AGAINST SELLER, ITS AFFILIATES OR ANY OTHER MEMBER OF THE SELLER GROUP UNDER APPLICABLE LAWS WITH RESPECT TO ENVIRONMENTAL DEFECTS, EXCEPT SOLELY FOR THOSE

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REMEDIES SET FORTH IN THIS ARTICLE 4.   Notwithstanding anything to the contrary in this Agreement, with respect to any alleged Environmental Defect that is not cured on or before Closing, if the Title Defect Amount with respect to such alleged Environmental Defect for the Asset affected by such Environmental Defect equals or exceeds fifty percent (50%) of the Allocated Value of such affected Asset, Purchaser shall have the option, but not the obligation, to exclude the affected Asset from the Assets delivered at Closing and the Unadjusted Purchase Price shall be reduced at Closing by the sum of the Allocated Values of such excluded Assets.

Section 4.3Title Benefits.

(a)Seller has the right, but not the obligation, to deliver to Purchaser on or before 11:59 p.m., Central Time, on the Title Claim Date with respect to each Title Benefit a notice (a “Title Benefit Notice”) in writing and including (i) a description of the Title Benefit reasonably sufficient to determine the basis of the alleged Title Benefit, (ii) the Property or Properties affected by such Title Benefit (each a “Title Benefit Property”), (iii) the Allocated Value of each Title Benefit Property, (iv) documents upon which Seller relies for its assertion of a Title Benefit, including supporting documents reasonably necessary for Purchaser to verify the existence of the alleged Title Benefit and (v) the amount by which Seller reasonably believes the Allocated Value of each Title Benefit Property is increased by such Title Benefit and the computations and information upon which Seller’s belief is based. Subject to Section 4.5(b)(ii), the Title Benefit Amount shall be used solely to offset against the Title Defect Amounts for the purpose of determining any downward adjustment to the Unadjusted Purchase Price.  Notwithstanding anything herein to the contrary, Seller forever waives Title Benefits not asserted by a Title Benefit Notice meeting all the requirements set forth in the preceding sentence by 11:59 p.m., Central Time, on the Title Claim Date.

(b)The “Title Benefit Amount” resulting from a Title Benefit shall be the amount by which the Allocated Value of the Title Benefit Property affected by such Title Benefit is increased as a result of the existence of such Title Benefit and shall be determined in accordance with the following methodology, terms and conditions:

(i)if Purchaser and Seller agree on the Title Benefit Amount, that amount shall be the Title Benefit Amount;

(ii)if the Title Benefit reflects a difference (with a proportionate increase in the Working Interest for the affected Title Benefit Property) between (A) the Net Revenue Interest for the affected Title Benefit Property and (B) the Net Revenue Interest stated in Exhibit A-2, then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the amount of the Net Revenue Interest increase and the denominator of which is the Net Revenue Interest stated in Exhibit A-2; and

(iii)if the Title Benefit represents a benefit in the ownership or title to the Title Benefit Property of a type not described in clause (ii) above, the Title Benefit Amount shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of the Title Benefit Property benefitted by the Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over

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the life of the Title Benefit Property, the values placed upon the Title Benefit by Purchaser and Seller and such other factors as are necessary to make a proper evaluation.

(c)If Seller and Purchaser cannot reach an agreement on alleged Title Benefits and Title Benefit Amounts by the scheduled Closing, the provisions of Section 4.4 shall apply.

Section 4.4Title Disputes.  Seller and Purchaser shall attempt to agree on all Title Defects and Title Benefits and Title Defect Amounts and Title Benefit Amounts, respectively, prior to Closing.  If Seller and Purchaser are unable to agree on Title Defects and Title Benefits and Title Defect Amounts and Title Benefit Amounts, respectively, by the scheduled Closing, then, subject to Section 4.2(c) and Section 4.2(d), as applicable, Seller’s good faith estimate shall be used to determine the Closing Payment pursuant to Section 9.4.  If Seller and Purchaser are unable to agree on an alleged Title Defect/Title Benefit (including, in the case of Title Defects, the adequate cure therefor) or Title Defect Amount/Title Benefit Amount (the “Disputed Title Matters”), such dispute(s), and only such dispute(s), shall be exclusively and finally resolved in accordance with the following provisions of this Section 4.4.  By not later than the tenth (10th) Business Day following the conclusion of the Cure Period, Purchaser shall provide to Seller in the case of Title Defects/Title Defect Amounts and Seller shall provide to Purchaser in the case of Title Benefits/Title Benefit Amounts, a written description meeting the requirements of Section 4.2(a) or Section 4.3(a), as applicable, together with all supporting documentation, of the Disputed Title Matters (with such Party providing the notice being referred to herein as the “Disputing Party”).  By not later than ten (10) Business Days after the other Party’s receipt of the Disputing Party’s written description of the Disputed Title Matters, such other Party shall provide to the Disputing Party a written response setting forth the other Party’s position with respect to the Disputed Title Matters together with all supporting documentation.

(a)By not later than ten (10) Business Days after the Disputing Party’s receipt of the other Party’s written response to the Disputing Party’s written description of the Disputed Title Matters, the Disputing Party may initiate a non-administered arbitration of any such dispute(s) conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent that such rules do not conflict with the terms of this Section, by written notice (the “Title Arbitration Notice”) to the other Party of any Disputed Title Matters not otherwise resolved or waived that are to be resolved by arbitration (“Final Disputed Title Matters”).

(b)The arbitration shall be held before a one (1) member arbitration panel (the “Title Arbitrator”), determined as follows.  The Title Arbitrator shall be an attorney with at least ten (10) years’ experience (i) in the case of Title Defects other than Environmental Defects, examining oil and gas titles in the State of Texas or Oklahoma, depending on the location of the applicable Title Defect Property and (ii) in the case of Environmental Defects, as an environmental attorney practicing in the State of Texas or Oklahoma, depending on the location of the applicable Title Defect Property.  Within two (2) Business Days following a Party’s receipt of the Title Arbitration Notice, Seller and Purchaser shall each exchange lists of three (3) acceptable, qualified arbitrators.  Within two (2) Business Days following the exchange of lists of acceptable arbitrators, Seller and Purchaser shall select by mutual agreement the Title Arbitrator from their original lists of three (3) acceptable arbitrators.  If no such agreement is

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reached within seven (7) Business Days following the delivery of Title Arbitration Notice, the Houston office of the American Arbitration Association shall select an arbitrator from the original lists provided by Seller and Purchaser to serve as the Title Arbitrator.

(c)Within three (3) Business Days following the selection of the Title Arbitrator, the Parties shall submit one copy to the Title Arbitrator of (i) this Agreement, with specific reference to this Section 4.4 and the other applicable provisions of this Article 4, (ii) the Disputing Party’s written description of the Final Disputed Title Matters, together with the supporting documents that were provided to the other Party, (iii) the other Party’s written response to the Disputing Party’s written description of the Final Disputed Title Matters, together with the supporting documents that were provided to the Disputing Party and (iv) the Title Arbitration Notice.  The Title Arbitrator shall resolve the Final Disputed Title Matters based only on the foregoing submissions.  Neither Purchaser nor Seller shall have the right to submit additional documentation to the Title Arbitrator nor to demand discovery on the other Party.

(d)The Title Arbitrator shall make its determination by written decision within thirty (30) days following receipt of the Title Arbitration Notice by Purchaser or Seller, as applicable, (the “Arbitration Decision”).  The Arbitration Decision shall be final and binding upon the Parties, without right of appeal.  In making its determination, the Title Arbitrator shall be bound by the provisions of this Article 4.  The Title Arbitrator may consult with and engage disinterested Third Parties to advise the Title Arbitrator, but shall disclose to the Parties the identities of such consultants and shall only use such Third Parties to the extent necessary to resolve the Final Disputed Title Matters.  Any such consultant shall not have worked as an employee or consultant for either Party or its Affiliates during the five (5) year period preceding the arbitration nor have any financial interest in the dispute.

(e)The Title Arbitrator shall act as an expert for the limited purpose of determining the specific Disputed Title Matter and shall not be empowered to award damages, interest or penalties to either Party with respect to any matter.

(f)Each Party shall each bear its own legal fees and other costs of preparing and presenting its case.  Seller shall bear one-half and Purchaser shall bear one-half of the costs and expenses of the Title Arbitrator, including any costs incurred by the Title Arbitrator that are attributable to the consultation of any Third Party.

(g)Except as taken into account or otherwise addressed under Section 4.2(f), any disputed Title Benefits and Title Benefit Amounts or Title Defects and Title Defect Amounts determined to be owed by either Party shall be accounted for in the final determination of the Purchase Price pursuant to Section 9.4(b).  The Arbitration Decision as to the Final Disputed Title Matters shall be final and binding on the Parties.

(h)Any dispute over the interpretation or application of this Section 4.4 shall be decided by the Title Arbitrator with reference to the Laws of the State of Texas.

Section 4.5Limitations.

(a)The right of Purchaser or Seller to assert a Title Defect or Title Benefit, respectively, under this Article 4 shall terminate on the Title Claim Date; provided, however, that

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until the alleged Title Defect or Title Benefit or Title Defect Amount or Title Benefit Amount, as applicable, is resolved in accordance with this Agreement, there shall be no termination of Purchaser’s or Seller’s rights under this Article 4 with respect to any alleged Title Defect or Title Benefit or Title Defect Amount or Title Benefit Amount properly reported in accordance with this Article 4 on or before 11:59 p.m., Central Time, on the Title Claim Date.  Thereafter, Purchaser’s and Seller’s sole and exclusive rights and remedies with regard to title to the Assets shall be, subject to Section 4.1, as set forth in the respective Conveyances.  Without limiting the foregoing, if a Title Defect under this Article 4 results from any matter which is also a breach of any representation or warranty of Seller as set forth in Article 5 and Purchaser has actual knowledge of such breach prior to the Title Claim Date, Purchaser shall only be entitled to assert such matter as a Title Defect to the extent permitted by this Article 4 and, for the avoidance of doubt, shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty or as a claim against Seller’s special warranty of title provided in the Conveyance after the Title Claim Date.

(b)Notwithstanding anything to the contrary in this Agreement, in no event shall there be any adjustments to the Unadjusted Purchase Price or other remedies available in respect of Title Defects (including, for purposes of certainty, Title Defects constituting Environmental Defects) or offset to Title Defects by any Title Benefits, as applicable, under this Article 4:

(i)With respect to Title Defects: (A) for any Title Defect Amount with respect to an individual Title Defect Property, if such amount does not exceed Seventy-Five Thousand Dollars ($75,000) (the “Individual Defect Threshold”); and (B) unless the aggregate amount of all such Title Defect Amounts (provided that each such Title Defect Amount exceeds the applicable Individual Defect Threshold), in the aggregate (excluding any Title Defect Amounts with respect to Title Defects cured or indemnified by Seller in accordance with this Article 4), exceeds two percent (2%) of the Unadjusted Purchase Price (the “Aggregate Defect Threshold”), after which point, subject to the applicable Individual Defect Thresholds, Purchaser shall be entitled to the remedies described hereunder only with respect to Title Defect Amounts in excess of an amount equal to one and one-half percent (1.5%) of the Unadjusted Purchase Price (the “Aggregate Defect Deductible”) and only to the extent that Title Defect Amounts exceed the Aggregate Defect Deductible.

(ii)With respect to Title Benefits: (A) for any Title Benefit Amount with respect to an individual Title Benefit Property, if such amount does not exceed Seventy-Five Thousand Dollars ($75,000) (the “Individual Benefit Threshold”); and (B) unless the aggregate amount of all such Title Benefit Amounts (provided that each such Title Benefit Amount exceeds the applicable Individual Benefit Threshold), in the aggregate, exceeds two percent (2%) of the Unadjusted Purchase Price (the “Aggregate Benefit Threshold”), after which point, subject to the applicable Individual Benefit Thresholds, Seller shall be entitled to offset Title Defect Amounts in excess of an amount equal to one and one-half percent (1.5%) of the Unadjusted Purchase Price (the “Aggregate Benefit Deductible”) and only to the extent that Title Benefit Amounts exceed the Aggregate Benefit Deductible.

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(c)Notwithstanding anything to the contrary, Purchaser will be responsible for all obligations and liabilities with respect to or arising from the Reassigned Properties arising out of or attributable to events occurring during the time in which Purchaser owns the Reassigned Properties.  Without limiting the preceding sentence, to the extent that Seller bears any responsibility for any such obligations or liabilities, Purchaser shall transfer and assign to Seller the benefit of any claims, causes of action and insurance proceeds and awards of Purchaser associated therewith.

(d)If the sum of (i) the aggregate Title Defect Amounts (excluding asserted Title Defect Amounts for any unresolved disputed Title Defects that Seller has disputed in good faith and any uncured Title Defects that Seller has elected, in good faith, to attempt to cure pursuant to Section 4.2(d)), plus (ii) the aggregate Allocated Values of Assets requiring consents to assign or waivers of preferential purchase rights for which a consent or waiver, as applicable, has not been obtained by the Closing Date, plus (iii) the estimated aggregated costs to repair or replace any portion of the Assets subject to a Casualty Loss that occurs after the Execution Date and prior to the Closing Date and any other Damages related thereto, plus (iv) the aggregate Allocated Values of Assets or portions thereof excluded from the transactions contemplated herein pursuant to Section 7.1(b), equals or exceeds twenty percent (20%) of the Unadjusted Purchase Price, then either Party, at its option exercised by the giving of written notice to the other Party, may elect to terminate this Agreement, in which event neither Party shall thereafter have any further rights or obligations hereunder, other than as set forth in Section 10.2.

(e)Without prejudice to any of the other dates by which performance or the exercise of rights is due hereunder, or the Parties’ rights or obligations in respect thereof, the Parties hereby acknowledge that, as set forth more fully in Section 13.14, time is of the essence in performing their obligations and exercising their rights under this Article 4, and, as such, that each and every date and time by which such performance or exercise is due shall be the firm and final date and time.

Section 4.6Consents to Assignment and Preferential Rights to Purchase.

(a)Promptly after the Execution Date, Seller shall prepare and send (i) notices to the holders of any required consents to assignment requesting consents to the Conveyances and (ii) notices to the holders of any applicable preferential rights to purchase or similar rights in compliance with the terms of such rights and requesting waivers of such rights.  Seller shall use commercially reasonable efforts to cause such consents to assignment and waivers of preferential rights to purchase or similar rights (or the exercise thereof) to be obtained and delivered prior to Closing, provided that Seller shall not be required to make payments or undertake obligations to or for the benefit of the holders of such rights in order to obtain the required consents and waivers.  Purchaser shall cooperate with Seller in seeking to obtain such consents to assignment and waivers of preferential rights.  Any preferential purchase right must be exercised subject to all terms and conditions set forth in this Agreement, including the successful Closing of this Agreement pursuant to Article 9 as to those Assets for which preferential purchase rights have not been exercised.  The consideration payable under this Agreement for any particular Asset for purposes of preferential purchase right notices shall be the Allocated Value for such Asset, subject to adjustment pursuant to Section 3.3.  If, prior to the Closing Date, any Party discovers any required consents or preferential rights to purchase (applying to the Assets) for which notices

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have not been delivered pursuant to the first sentence of this Section 4.6(a), then (A) the Party making such discovery shall provide the other Party with written notification of such consents or preferential rights, as applicable, (B) Seller, following delivery or receipt of such written notification, will promptly send notices to the holders of the required consents requesting consents to the Conveyances and notices to the holders of preferential rights to purchase in compliance with the terms of such rights and requesting waivers of such rights and (C) the terms and conditions of this Section 4.6 shall apply to the Assets subject to such consents or preferential rights to purchase, as applicable.

(b)In no event shall there be transferred at Closing any Asset for which a consent requirement has not been satisfied and which will terminate or in which the rights to be transferred to Purchaser will be materially impaired if transferred without the consent.  In cases in which the Asset subject to such a requirement is a Contract and Purchaser is assigned the Property or Properties to which the Contract relates, but the Contract is not transferred to Purchaser due to the unwaived consent requirement, Seller shall continue after Closing to use commercially reasonable efforts to obtain the consent so that such Contract can be transferred to Purchaser upon receipt of the consent.  As to any such Contract that is not transferred to Purchaser due to the unwaived consent requirement, until any such consent is obtained, to the extent permissible under Law and under the terms of such Contract, Seller shall post-Closing (i) continue to perform the liabilities and obligations under or with regard to such Contract, (ii) hold such Contract for the benefit of Purchaser (provided that, following the Closing, Purchaser will be responsible for making all payments, and indemnifying Seller for any obligations, arising under any such Contract during such period) and shall promptly forward to Purchaser any monies or other benefits received that are attributable to such Contract, and (iii) endeavor to mutually agree with Purchaser to institute alternative arrangements intended to put the Parties in substantially the same economic position as if such non-assigned Contract had been assigned.  If the foregoing arrangements are not permissible under Law or under the terms of such Contract, then the Parties shall use commercially reasonable efforts to take such other actions or put into place such other arrangements as are permissible with regard to the non-assigned Contract so as to provide the Parties with the same economic results as would otherwise have resulted.  In cases in which the Asset subject to such a consent requirement is a Property and such consent requirement is not obtained by Closing, the affected Property and the Assets related to that Property shall not be transferred at Closing and the Unadjusted Purchase Price shall be reduced by the Allocated Value of the Property and related Assets.  If an unsatisfied consent requirement with respect to which a Purchase Price adjustment is made under Section 3.3 is subsequently satisfied prior to the date of delivery of the final settlement statement under Section 9.4(b), a separate closing shall be held within five (5) Business Days thereof at which (A) Seller shall convey the affected Property and related Assets to Purchaser in accordance with this Agreement and (B) Purchaser shall pay an amount equal to the Allocated Value of such Property and related Assets, adjusted in accordance with Section 3.3, to Seller.  If such consent requirement is not satisfied by the date of delivery of the final settlement statement, Seller shall have no further obligation to sell and convey such Property and related Assets and Purchaser shall have no further obligation to purchase, accept and pay for such Property, and the affected Property and related Assets shall be deemed to be deleted from Exhibit A-1 and Exhibit A-2 (and the other applicable Exhibits and Schedules) to this Agreement for all purposes.

(c)If any preferential right to purchase any Assets is exercised prior to

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Closing, the Unadjusted Purchase Price shall be decreased by the Allocated Value for such Assets, and the affected Assets shall be deemed to be deleted from Exhibit A-1 and Exhibit A-2 (and the other applicable Exhibits and Schedules) to this Agreement for all purposes.  Seller shall retain the consideration paid by the Third Party, and shall have no further obligation with respect to such affected Assets under this Agreement.  Should a Third Party fail to exercise its preferential right to purchase as to any portion of the Assets prior to Closing and the time for exercise or waiver has not yet expired, the affected Assets shall not be transferred at Closing and the Unadjusted Purchase Price shall be reduced by the Allocated Values of such Assets.  In the event that such Third Party exercises its preferential right to purchase following the Closing, Seller shall have no further obligation to sell and convey the affected Assets and Purchaser shall have no further obligation to purchase, accept and pay for such affected Assets, and the affected Assets shall be deemed to be deleted from Exhibit A-1 and Exhibit A-2 (and the other applicable Exhibits and Schedules) to this Agreement for all purposes.  If, on the other hand, the applicable preferential purchase rights are waived or expire, a separate closing shall be held within five (5) Business Days thereof at which (i) Seller shall convey the affected Assets to Purchaser in accordance with this Agreement and (ii) Purchaser shall pay an amount equal to the Allocated Value of such Assets, adjusted in accordance with Section 3.3, to Seller.

Section 4.7Casualty or Condemnation Loss.  If, after the Execution Date, but prior to the Closing Date, any portion of the Assets suffers a Casualty Loss, subject to Section 4.5(d), Purchaser shall nevertheless be required to close, and Seller shall elect by written notice to Purchaser prior to Closing either (i) to cause the Assets adversely affected by any such individual Casualty Loss to be repaired or restored to at least their condition prior to such Casualty Loss, at Seller’s sole cost and expense, as promptly as reasonably practicable (which work may extend after the Closing Date), (ii) to indemnify Purchaser, pursuant to an indemnity agreement reasonably acceptable to Purchaser, against any costs or expenses that Purchaser reasonably incurs to repair or restore the Assets subject to any such Casualty Loss or (iii) exclude the affected Assets from this Agreement.  In each case, Seller shall retain all rights to insurance, unpaid awards, condemnation payments and other rights and claims against Third Parties with respect to the Casualty Loss, except to the extent the Parties otherwise agree in writing.

ARTICLE 5
REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1Generally.

(a)Any representation or warranty qualified to the “knowledge of Seller” or “to Seller’s knowledge” or with any similar knowledge qualification is limited to matters within the Actual Knowledge of the individuals listed in Schedule 5.1.  As used herein, the term “Actual Knowledge” means information actually known by such individual.

(b)Inclusion of a matter on a Schedule to this Agreement in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on such Schedule.  Matters may be disclosed on a Schedule for information purposes only.

(c)Subject to the foregoing provisions of this Section 5.1, the disclaimers and

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waivers contained in and the other terms and conditions of this Agreement, Seller represents and warrants to Purchaser the matters set out in Section 5.2 through Section 5.20.

Section 5.2Existence and Qualification.  Seller is a limited liability company, validly existing and in good standing under the Laws of the State of Delaware and is duly qualified to do business in the States of Texas and Oklahoma.

Section 5.3Power.  Seller has the requisite power to enter into and perform its obligations under this Agreement and consummate the transactions contemplated by this Agreement.

Section 5.4Authorization and Enforceability.  The execution, delivery and performance of this Agreement and all documents required to be executed and delivered by Seller at Closing, and the performance of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary limited liability company action on the part of Seller.  This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 5.5No Conflicts.  The execution, delivery and performance of this Agreement by Seller, and the transactions contemplated by this Agreement, will not (a) violate any provision of the organizational documents of Seller, (b) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any material note, bond, mortgage, indenture, license or agreement to which Seller is a party or which affects the Assets, (c) violate any judgment, order, ruling or decree applicable to Seller as a party in interest, or (d) violate any Laws applicable to Seller or any of the Assets.

Section 5.6Liability for Brokers’ Fees.  Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with the negotiation, execution or delivery of this Agreement or any agreement or transaction contemplated hereby.

Section 5.7Litigation.  Except as set forth on Schedule 5.7, there are no actions, suits, demands or proceedings pending or, to Seller’s knowledge, being contemplated or threatened in writing by a Person, before any Governmental Body, arbitrator or mediator to which Seller is a party or to which the Assets are subject, or that would otherwise impair Seller’s ability to perform its obligations under this Agreement or any document required to be executed and delivered by Seller at Closing.

Section 5.8Consents and Preferential Purchase Rights.  Except as set forth in Schedule 5.8, none of the Properties or any portion thereof is subject to any preferential rights to

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purchase or required Third Party consents to assignment which may by applicable to the transactions contemplated by this Agreement, except for consents and approvals of assignment by Governmental Bodies that are customarily obtained after Closing (including Customary Post-Closing Consents), if such Governmental Bodies are, pursuant to applicable Law, without discretion to refuse to grant such consent if certain specifically enumerated conditions set forth in such applicable Law are satisfied.

Section 5.9Non-Consent Operations.  Except as set forth on Schedule 5.9, as of the date hereof, no operations are being conducted or have been conducted on the Properties with respect to which Seller has elected to be a non-consenting party under the applicable operating agreement and with respect to which all of Seller’s rights have not yet reverted to it. Schedule 5.9 contains a list of the status of any payout balances of which Seller has knowledge for each Property that is currently subject to a non-consent election, reversion or other adjustment at any level of cost recovery or Hydrocarbon production under an operating agreement, unit agreement, pooling agreement, farmout agreement, development agreement or any other contracts, agreements or instruments listed on Schedule 5.12, in each case, as of the dates shown on Schedule  5.9 with respect to each Property.

Section 5.10Taxes and Assessments.

(a)All material Asset Taxes that have become due and payable have been properly paid.

(b)All Tax Returns with respect to Asset Taxes that are required to be filed by the owner of the Assets have been filed, and all such Tax Returns are true, correct and complete in all material respects.

(c)No action, suit, Governmental Body proceeding or audit is now in progress or pending with respect to Seller or with respect to the Assets, and Seller has not received notice of any pending claim against it from any applicable Governmental Body for assessment of Asset Taxes and no such claim has been threatened.

(d)No audit, litigation or other proceeding with respect to Asset Taxes has been commenced or is presently pending.  Seller has not granted an extension of waiver of the statute of limitations applicable to any Tax Return or to any Assets Taxes, which period has not yet expired.

(e)Seller is not a party to or bound by any Tax allocation or Tax sharing or indemnification agreement with respect to the Assets.

(f)None of the Assets are subject to tax partnership reporting for federal or state income tax purposes.

(g)None of the Assets are “tax exempt use property” within the meaning of Section 168(h) of the Code or “tax exempt use property” within the meaning of Section 168(g)(5) of the Code.

(h)All of the Assets that are subject to property tax have been properly listed

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and described on the property tax rolls of the appropriate Governmental Body for all assessment dates prior to Closing.

(i)To Seller’s knowledge, Seller has complied with all escheat or unclaimed property laws with respect to funds or property received in connection with owning or operating the Assets.

Section 5.11Capital Commitments.  Except as disclosed on Schedule 5.11, as of the Effective Time, there were no outstanding AFEs or other capital commitments to Third Parties that were binding on the Assets and could reasonably be expected to require expenditures by the owner of such Assets after the Effective Time in excess of One Hundred Fifty Thousand and No/100 Dollars ($150,000.00).

Section 5.12Contracts.  Except as disclosed on Schedule 5.12:

(a)Neither Seller, nor to the knowledge of Seller, any other Person, is in default under any Contract.

(b)There are no (i) Contracts with Affiliates of Seller that will be binding on the Assets after Closing, (ii) contracts to sell, lease, farmout, exchange or otherwise dispose of all or any part of the Assets, (iii) non-competition agreements or any agreements that purport to restrict, limit or prohibit a Person from engaging in any line of business or the manner in which, or the locations at which, Seller (or Purchaser, as successor in interest to Seller) conducts business, including area of mutual interest agreements, or (iv) futures, options, hedges, swaps, derivatives or other similar contracts that are currently binding on the Assets or will be binding on the Assets after Closing.

(c)None of the Properties are subject to or burdened by any Contract that can be reasonably expected to result in aggregate payments or receipts of revenue by Seller of more than One Hundred Fifty Thousand and No/100 Dollars ($150,000.00) during the current or any subsequent year, including (i) any operating agreement, transportation agreement, exploration agreement, joint development agreement, participation agreement and processing or similar contract or Hydrocarbon sales, purchase or exchange contract (in each case) that is not terminable without penalty on sixty (60) days’ or less notice or (ii) any indenture, mortgage, loan, deed of trust, note purchase agreement, credit or sale-leaseback, guaranties, bonds, letters of credit or similar contract that will not be terminated with respect to the Assets at or prior to Closing.

(d)No written notice of default or breach has been received or delivered by Seller under any Contract, the resolution of which is outstanding as of the date hereof or as of the Closing, and there are no current notices received by Seller of the exercise of any premature termination, price redetermination, market-out, or curtailment of any Contract.  As of the Closing Date, Seller has made available to Purchaser (or its Representatives) true and complete copies of each Contract and all amendments or modifications thereto.

Section 5.13Wells and Equipment.  Except as set forth on Schedule 5.13:

(a)during the period in which Seller has owned the Assets (and limited to

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Seller’s knowledge for instances in which Sabine Parent is not the operator of the relevant Properties), all Wells have been drilled and completed at legal locations and within the limits permitted by all applicable Leases, Contracts and pooling or unit agreements;

(b)no Well is subject to penalties on allowables on or after the Effective Time because of any overproduction or any other violation of Laws, in each case, during the time in which Seller has owned the Assets (and limited to Seller’s knowledge for instances in which Sabine Parent is not the operator of the relevant Properties); and there are no Wells located on the Assets that: (i) Seller is currently obligated by any Laws or Contract to currently plug, dismantle or abandon; (ii) to Seller’s knowledge, have been plugged, dismantled or abandoned in a manner that does not comply in all material respects with applicable Laws; or (iii) are on expired leases or leases in which Seller has no interest and are currently required to be plugged, dismantled or abandoned;

(c)to Seller’s knowledge (i) all currently producing Wells and Equipment are in an operable state of repair adequate to maintain normal operations in accordance with past practices, ordinary wear and tear excepted, and (ii), without limiting the foregoing, do not contain junk, fish or other obstructions which could reasonably be expected to materially interfere with drilling, completion, recompletion, stimulation or other operations on, with respect to or affecting the Properties; and

(d)Seller has (i) title to the Equipment free and clear of liens, encumbrances, obligations and defects or (ii) with respect to rented Equipment, a good and valid leasehold interest in such Equipment, in each case, other than Excluded Defects and Permitted Encumbrances.

Section 5.14Environmental Matters.

(a)With respect to the Assets, neither Seller nor Sabine Parent has entered into, or, to Seller’s knowledge, is subject to, any agreements, orders, decrees, judgments, licenses or permit conditions, or other directives of any Governmental Bodies, that are in existence as of the Execution Date, that are based on any Environmental Laws, that relate to the future use of any of the Assets and that require any material change in the present condition of any of the Assets.

(b)As of the Execution Date, neither Seller nor Sabine Parent has received written notice from any Third Parties of any release or disposal of any Hazardous Substance concerning any land, facility, asset or property included in the Assets that (i) interferes with or prevents compliance by the operator of the Assets with any Environmental Law or the terms of any license or permits issued pursuant thereto; or (ii) gives rise to or results in any common law, contractual or other liability of Seller with respect to the Assets, which in the case of either clause (i) or (ii) would reasonably be expected to be material in nature.

Section 5.15Bankruptcy.  There are no bankruptcy, insolvency, reorganization, receivership or similar proceedings pending against, being contemplated by or, to Seller’s knowledge, threatened against Seller or any Affiliate thereof (whether by Seller or a Third Party). Seller is not entering into this Agreement with actual intent to hinder, delay or defraud

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any creditor.

Section 5.16Permits.  To Seller’s knowledge, except as set forth on Schedule 5.16: (i) Seller has acquired all Permits from appropriate Governmental Bodies to conduct operations on the Assets in material compliance with all applicable Laws; (ii) all such Permits are in full force and effect and no action, claim or proceeding is pending, nor to the knowledge of Seller, threatened, to suspend, revoke or terminate any such Permit or declare any such Permit invalid; (iii) Seller is in compliance in all material respects with all such Permits; (iv) there are no violations of any such Permit that would (or could with notice or lapse of time) result in the termination of such Permit; and (v) the transactions contemplated by this Agreement will not adversely affect the validity of any such Permit or cause a cancellation of or otherwise adversely affect such Permit.

Section 5.17Payments for Production; Imbalances.  To Seller’s knowledge, (a) except as set forth on Schedule 5.17, Seller is not obligated by virtue of a take-or-pay payment, advance payment, or other similar payment (other than royalties, overriding royalties, similar arrangements established in the Leases), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to Seller’s interest in the Properties at some future time without receiving payment therefor at or after the time of delivery and (b) Schedule 5.17 lists all production, transportation, plant, or other imbalances with respect to production from the Properties.

Section 5.18Suspended Proceeds.  To Seller’s knowledge, Schedule 5.18 sets forth a list of all Suspense Funds, a description of the source of such Suspended Funds and the reason they are being held in suspense, the agreement or agreements under which such funds are being held and the name or names of the parties claiming such funds or to whom such funds are owed.

Section 5.19Leases.  During the period in which Seller has owned the Assets (limited to Seller’s knowledge for instances in which Sabine Parent is not the operator of the relevant Properties) and, to Seller’s knowledge, for all other periods, the lessee has timely and properly paid all accrued bonuses, delay rentals, minimum royalties, and royalties due with respect to Seller’s interest in the Leases, in each case in accordance with the Leases and applicable Law.  To Seller’s knowledge, Schedule 5.19 contains a true, correct, and complete list of all Leases that (a) are currently held by payment of shut-in royalties, reworking operations, any substitute for production in paying quantities, or any other means other than production in paying quantities, and (b) will expire, terminate, or otherwise be materially impaired absent actions by or on behalf of Seller (other than continued production in paying quantities) on or before a date that is ninety (90) days after the target Closing Date.

Section 5.20Availability of Properties.  The Assets (together with the Excluded Assets) constitute and include all of the assets necessary for Seller’s operation of its business in respect of the Assets as it is currently operated.

Section 5.21Certain Disclaimers.

(a)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, THIS ARTICLE 5, IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(C) OR IN THE CONVEYANCES TO BE

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DELIVERED BY SELLER TO PURCHASER HEREUNDER, (i) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (ii) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO THE PURCHASER GROUP (INCLUDING ANY OPINION, INFORMATION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY PERSON OF THE SELLER GROUP).

(b)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, THIS ARTICLE 5, IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(C) OR IN THE CONVEYANCES TO BE DELIVERED BY SELLER TO PURCHASER HEREUNDER, WITHOUT LIMITING THE GENERALITY OF SECTION 5.21(A), SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, ORAL OR WRITTEN, AS TO (i) TITLE TO ANY OF THE ASSETS, (ii) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (iii) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (iv) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (v) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS OR IN PAYING QUANTITIES, (vi) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS OR (vii) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO THE PURCHASER GROUP IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO (INCLUDING ANY ITEMS PROVIDED IN CONNECTION WITH SECTION 7.1), AND FURTHER DISCLAIM ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE EQUIPMENT AND OTHER TANGIBLE PROPERTY TRANSFERRED HEREUNDER IN ITS PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS, AND THAT, AS OF CLOSING, PURCHASER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE.

(c)EXCEPT AS AND TO THE EXTENT EXPRESSLY PROVIDED IN ARTICLE 4, SECTION 5.14 OR SECTION 11.2(B)(III), SELLER SHALL NOT HAVE ANY LIABILITY IN CONNECTION WITH AND HAS NOT AND WILL NOT MAKE (AND HEREBY DISCLAIMS) ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL DEFECTS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF HAZARDOUS SUBSTANCES, HYDROCARBONS

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OR NORM  INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

ARTICLE 6
REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to Seller the following:

Section 6.1Existence and Qualification.  Purchaser is a limited liability company, validly existing and in good standing under the Laws of the State of Delaware and is duly qualified to do business in the States of Texas and Oklahoma.

Section 6.2Power.  Purchaser has the requisite power to enter into and perform its obligations under this Agreement and consummate the transactions contemplated by this Agreement.

Section 6.3Authorization and Enforceability.  The execution, delivery and performance of this Agreement and all documents required to be executed and delivered by Purchaser at Closing, and the performance of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary limited liability company action on the part of Purchaser.  This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 6.4No Conflicts.  The execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated by this Agreement, will not (a) violate any provision of the organizational documents of Purchaser, (b) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any material note, bond, mortgage, indenture, license or agreement to which Purchaser is a party, (c) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, or (d) violate any Laws applicable to Purchaser.

Section 6.5Liability for Brokers’ Fees.  Seller shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with the negotiation, execution or delivery of this Agreement or any

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agreement or transaction contemplated hereby.

Section 6.6            Litigation.  There are no actions, suits, demands or proceedings pending, or, to Purchaser’s knowledge, being contemplated or threatened in writing by a Person, before any Governmental Body, arbitrator or mediator against Purchaser which would materially impair Purchaser’s ability to perform its obligations under this Agreement or any document required to be executed and delivered by Purchaser at Closing.  As used in this Section 6.6, “Purchaser’s knowledge” is limited to information personally known by the individuals listed in Schedule 6.6.

Section 6.7            Financing.  Purchaser has and will maintain between the Execution Date and Closing sufficient cash, available lines of credit or other sources of immediately available funds (in Dollars) to enable it to pay the Closing Payment to Seller at the Closing.

Section 6.8            Securities Law Compliance.  Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act of 1933, as amended, and applicable state securities Laws.

Section 6.9            Independent Evaluation.

(a)           Purchaser is knowledgeable of the oil and gas business and of the usual and customary practices of oil and gas producers, including those in the areas where the Assets are located.

(b)           Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent purchaser would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability.

(c)           In making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the basis of its own independent due diligence investigation of the Assets and the terms and conditions of this Agreement.

Section 6.10          Consents, Approvals or Waivers.  Purchaser’s execution, delivery and performance of this Agreement (and any document required to be executed and delivered by Purchaser at Closing) is not and will not be subject to any consent, approval, or waiver from any Governmental Body or other Third Party, except Customary Post-Closing Consents.

Section 6.11          Bankruptcy.  There are no bankruptcy, insolvency, reorganization or receivership proceedings pending against, being contemplated by, or threatened against Purchaser.

Section 6.12          Qualification.  Purchaser is, or as of the Closing Date will be, qualified under applicable Law to own the Assets and has, or as of the Closing will have, complied with all necessary bonding requirements of Governmental Bodies required for Purchaser’s ownership or operation of the Assets.

Section 6.13          Limitation.  Purchaser acknowledges the following:

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(a)           EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, ARTICLE 5, IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(C) OR IN THE CONVEYANCES TO BE DELIVERED BY SELLER TO PURCHASER HEREUNDER, THERE ARE NO REPRESENTATIONS AND WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, BY SELLER AS TO THE ASSETS OR PROSPECTS THEREOF AND PURCHASER HAS NOT RELIED UPON ANY ORAL OR WRITTEN INFORMATION PROVIDED BY SELLER.

(b)           EXCEPT AS AND TO THE EXTENT EXPRESSLY PROVIDED IN ARTICLE 4, SECTION 5.14 OR SECTION 11.2(B)(III), SELLER AND THE OTHER MEMBERS OF THE SELLER GROUP SHALL NOT HAVE ANY LIABILITY IN CONNECTION WITH AND SELLER HAS DISCLAIMED, HAS NOT MADE AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL DEFECTS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF HAZARDOUS SUBSTANCES, HYDROCARBONS OR NORM INTO THE ENVIRONMENT OR PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS.

(c)           THE ASSETS HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT AND PRODUCTION OF HYDROCARBONS AND THERE MAY BE PETROLEUM, PRODUCED WATER, WASTE, OR OTHER SUBSTANCES OR MATERIALS LOCATED IN, ON OR UNDER THE PROPERTIES OR ASSOCIATED WITH THE ASSETS.  EQUIPMENT AND SITES INCLUDED IN THE ASSETS MAY CONTAIN ASBESTOS, NORM OR OTHER HAZARDOUS SUBSTANCES.  NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE, OR IN OTHER FORMS.  THE WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE PROPERTIES OR INCLUDED IN THE ASSETS MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES.  NORM CONTAINING MATERIAL AND/OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING WATER, SOILS OR SEDIMENT.  SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE ASSETS.

ARTICLE 7
COVENANTS OF THE PARTIES

Section 7.1            Access.

(a)           Between the Execution Date and the Closing Date, Seller will give Purchaser and its Representatives access to the Assets and access to and the right to copy, at Purchaser’s sole cost and expense, the Records (or originals thereof) and Contracts, for the purpose of conducting a confirmatory review of the Assets, but only to the extent that Seller may

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do so without violating any obligations to any Third Party and to the extent that Seller has the authority to grant such access without breaching any restriction binding on it.  Seller shall cooperate with Purchaser in Purchaser’s efforts to obtain, at Purchaser’s expense, such additional information relating to the Assets as Purchaser may reasonably request. Seller shall use reasonable efforts (including the assertion of any rights of Seller to information to which Seller is entitled pursuant to an applicable joint operating agreement) to obtain permission for Purchaser to gain access to Properties operated by third Persons and the records and files of such third Persons to inspect the condition of such Properties, records, and files. Purchaser shall be entitled to conduct, at its sole cost, risk and expense, a Phase I Environmental Site Assessment of the Assets and may conduct visual inspections and record reviews relating to the Assets, including their condition and compliance with Environmental Laws, provided Purchaser shall provide Seller at least two (2) Business Days’ notice prior to conducting any on-site inspections in connection with such assessments. Purchaser shall not operate any equipment or conduct any testing or sampling of soil, groundwater or other materials (including any testing or sampling for Hazardous Substances, Hydrocarbons or NORM) on or with respect to the Assets prior to Closing without the prior written consent of Seller (which may be withheld in Seller’s sole discretion).  Purchaser shall abide by Seller’s, Sabine Parent’s, and any Third Party operator’s safety rules, regulations and operating policies provided to Purchaser at or prior to the time of Purchaser’s access (including the execution and delivery of any documentation or paperwork, e.g., boarding agreements or liability releases, required by Third Party operators with respect to Purchaser’s access to any of the Assets) while conducting its on-site due diligence evaluation of the Assets.  Any conclusions made from any examination done by Purchaser shall result from Purchaser’s own independent review and judgment.  Seller shall have the right to observe any inspection or examination of the Assets conducted by Purchaser, and shall promptly receive a copy of all results, analyses and third party reviews, except for such information for which Purchaser has an attorney-client privilege.

(b)           (i)            In the event that Purchaser’s Phase I Environmental Site Assessment identifies actual or potential “recognized environmental conditions” with respect to any Asset, then Purchaser may request (any such request, a “Phase II Request”) in writing Seller’s permission to conduct additional Phase II environmental property assessments to further assess such conditions.  Each Phase II Request will state with reasonable specificity (i) the actual or potential “recognized environmental conditions” identified and (ii) the proposed scope of the Phase II assessment, including a description of the activities to be conducted, and a description of the approximate location and expected timing of such activities. Seller may, in its sole discretion, approve said Phase II environmental property assessment plan, in whole or in part, and Purchaser shall not have the right to conduct any activities set forth in such plan until such time that Seller has approved such plan in writing. Any such approved Phase II environmental property assessment plan shall be conducted by a reputable environmental consulting or engineering firm, approved in advance by Seller (such approval not to be unreasonably withheld or delayed).

(ii)           If Seller does not provide its consent to any Phase II Request delivered in accordance with the terms within two (2) Business Days of Purchaser’s delivery of such request, Purchaser may elect to exclude the affected Asset to be conveyed at Closing, and such Asset (or portion thereof affected) shall become Excluded

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Assets.  At Closing, the Allocated Value of all Assets excluded pursuant to this Section 7.1(b) shall be accounted for as a downward adjustment to the Unadjusted Purchase Price pursuant to Section 3.3(b).

(c)           The access granted to Purchaser under this Section 7.1 shall be limited to Seller’s normal business hours with reasonable notice, and Purchaser’s investigation shall be conducted in a manner that minimizes interference with the operation of the Assets.  Purchaser shall coordinate its access rights of the Assets with Seller to reasonably minimize any inconvenience to or interruption of the conduct of business by Seller.

(d)           Purchaser acknowledges that, pursuant to its right of access to the Assets, Purchaser will become privy to confidential and other information of Seller and that such confidential information (which includes Purchaser’s conclusions with respect to its evaluations) shall be held confidential by Purchaser in accordance with the terms of the Confidentiality Agreement and any applicable privacy Laws regarding personal information.

(e)           In connection with the rights of access, examination and inspection granted to Purchaser under this Section 7.1, (i) PURCHASER WAIVES AND RELEASES ALL CLAIMS AGAINST THE SELLER GROUP ARISING IN ANY WAY THEREFROM OR IN ANY WAY CONNECTED THEREWITH AND (ii) PURCHASER HEREBY AGREES TO INDEMNIFY, DEFEND AND HOLD HARMLESS EACH MEMBER OF THE SELLER GROUP AND THIRD PARTY OPERATORS FROM AND AGAINST ANY AND ALL DAMAGES ATTRIBUTABLE TO PERSONAL INJURY, DEATH OR PHYSICAL PROPERTY DAMAGE, OR VIOLATION OF THE SELLER GROUP’S OR ANY THIRD PARTY OPERATOR’S RULES, REGULATIONS, OR OPERATING POLICIES, TO THE EXTENT ARISING OUT OF, RESULTING FROM OR RELATING TO ANY FIELD VISIT OR OTHER DUE DILIGENCE ACTIVITY CONDUCTED BY PURCHASER WITH RESPECT TO THE ASSETS, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, SOLELY OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW BY THE SELLER GROUP OR THIRD PARTY OPERATORS.

Section 7.2            Government Reviews.  In a timely manner, Seller and Purchaser shall (a) make all required filings, prepare all required applications and conduct negotiations with each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and (b) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations. Seller shall reasonably cooperate with and assist Purchaser in pursuing such filings, applications and negotiations, and Purchaser shall reasonably cooperate with and assist Seller with respect to such filings, applications and negotiations.  Each Party shall be responsible for and shall make any governmental filings occasioned by the ownership or structure of such Party.

Section 7.3            Public Announcements; Confidentiality.

(a)           Neither Seller nor Purchaser shall make any press release or other public

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announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the other Party; provided, however, that the foregoing shall not restrict disclosures to the extent (i) necessary for a Party to perform this Agreement (including disclosures to Governmental Bodies or Third Parties holding preferential rights to purchase, rights of consent or other rights that may be applicable to the transaction contemplated by this Agreement, as reasonably necessary to provide notices, seek waivers, amendments or termination of such rights, or seek such consents), (ii) required by applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the Parties or their respective Affiliates or (iii) required as part of Seller’s or its Affiliates’ obligations under any indenture agreement or similar arrangement (including any disclosures, irrespective of whether or not required under such indenture or other arrangement, made by Seller on the external website of Seller or any of its Affiliates in connection with any such required disclosure) to which Seller or its Affiliates is a party; and provided, further, that, in the case of clauses (i) and (ii), each Party shall use its reasonable efforts to consult with the other Party regarding the contents of any such release or announcement prior to making such release or announcement.

(b)           Except as required by Law or the applicable rules of any stock exchange having jurisdiction over the Parties or their respective Affiliates, the Parties shall continue to be bound by confidentiality terms, conditions and obligations substantially similar to those set forth in the Confidentiality Agreement, which such terms, conditions and obligations will apply mutatis mutandis to this Agreement for an indefinite period of time.

Section 7.4            Operation of Business.  Except as to the matters set forth on Schedule 7.4 or as otherwise approved by Purchaser in writing (which approval shall not be unreasonably withheld, conditioned or delayed), from the Execution Date until the Closing Date, Seller will, and will cause Sabine Parent to (in each case, as applicable):

(a)           conduct its business related to the Assets in the ordinary course consistent with Seller’s recent exploration and drilling program and prudent industry practice;

(b)           not commit to any new operation on the Assets, or incur any contractual obligation or liability, reasonably anticipated by Seller or Sabine Parent to require future capital expenditures by the owner of the Assets in excess of One Hundred Fifty Thousand and No/100 Dollars ($150,000.00) (excepting ongoing commitments under existing AFEs, and operations undertaken to avoid a monetary penalty or forfeiture provision of any applicable Contract or order, provided that Seller gives to Purchaser an advance notice of such operations);

(c)           not voluntarily terminate, amend, execute or extend any Contracts;

(d)           maintain insurance coverage on the Assets presently furnished by nonaffiliated Third Parties in the amounts and of the types presently in force and not make any election to be excluded from any coverage provided by an operator for the joint account pursuant to a joint operating agreement or similar agreement;

(e)           maintain in full force and effect all Leases and comply with all express or implied covenants contained therein;

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(f)            not abandon any Well on any Lease capable of commercial production, or release or abandon all or any part of the Assets capable of commercial production, or release or abandon all or any portion of the Leases;

(g)           maintain all Permits, approvals, bonds and guaranties affecting the Assets, and make all filings that Seller is required to make under applicable Law with respect to the Assets;

(h)           not transfer, sell, hypothecate, encumber or otherwise dispose of any material Properties or Equipment except for sales and dispositions of Equipment made in the ordinary course of business consistent with past practices;

(i)            not create any lien, security interest or other encumbrance with respect to the Assets (except for Permitted Encumbrances), or (i) enter into any agreement for the sale, disposition or encumbrance of any of the Assets, or (ii) dedicate, sell, encumber or dispose of any oil and gas production, except in the ordinary course of business on a contract which is terminable on not more than thirty (30) days’ notice except production sold under a contract listed on Schedule 5.12;

(j)            grant any preferential right or other right to purchase or agree to require the consent of any party not otherwise required to consent to the transfer and assignment of the Assets to Purchaser;

(k)           not voluntarily relinquish its position as operator to anyone other than Purchaser with respect to any of the Assets, or voluntarily abandon any of the Assets other than as required pursuant to the terms of a Lease or applicable Law; and

(l)            not enter into an agreement with respect to any of the foregoing.

Requests for approval of any action restricted by this Section 7.4 shall be delivered to the following individual, who shall have full authority to grant or deny such requests for approval on behalf of Purchaser:

Jody Crook

Fax:  (512) 329-5394

Email: jcrook@jonesenergy.com

Purchaser’s approval of any action restricted by this Section 7.4 shall be considered granted within ten (10) days (unless a shorter time is reasonably required by the circumstances and such shorter time is specified in Seller’s notice) after Seller’s notice to Purchaser requesting such consent unless Purchaser notifies Seller to the contrary during that period.  In the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Purchaser of such action promptly thereafter.  In cases in which Sabine Parent is not the operator of any portion of the Assets, to the extent that the actions described in this Section 7.4 may only be taken by (or are the primary responsibility of) the operator of such Assets, the provisions of this Section 7.4 shall be construed to require only that Seller use commercially reasonable efforts to cause the operator(s) of such Assets to take such actions within the constraints of the applicable operating agreements and other applicable agreements.

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Section 7.5            Operatorship.  Seller shall cause Sabine Parent to deliver to Purchaser at the Closing notices to the co-owners of those Properties that Sabine Parent currently operates indicating that Sabine Parent is resigning as operator, and recommending that Purchaser or Purchaser’s designee be elected successor operator. Purchaser shall deliver the notices to the co-owners of such Properties following the Closing.  Seller makes no representations or warranties to Purchaser as to the transferability of operatorship of any Properties which Sabine Parent currently operates; provided that Seller shall, and shall cause Sabine Parent to, exercise commercially reasonable efforts (including providing reasonable assistance to Purchaser or Purchaser’s designee in connection therewith) to allow Purchaser or Purchaser’s designee to succeed Sabine Parent as operator of all such Properties.  Rights and obligations associated with operatorship of the Properties are governed by operating agreements or similar agreements and will be decided in accordance with the terms of such agreements.

Section 7.6            Change of Name.  Within thirty (30) days after Closing, Purchaser shall eliminate the name “Sabine Oil & Gas LLC” and any variants thereof from the Assets acquired pursuant to this Agreement and shall have no right to use any logos, trademarks or trade names belonging to Seller, Sabine Parent or any of its or their Affiliates.

Section 7.7            Replacement of Insurance, Bonds, Letters of Credit and Guaranties.  The Parties understand that none of the insurance currently maintained by Sabine Parent covering the Assets, nor any of the bonds, letters of credit and guaranties, if any, posted by Sabine Parent with Governmental Bodies or co-owners and relating to the Assets will be transferred to Purchaser.  Promptly following Closing, but, as to Properties operated by Sabine Parent, in no event later than the transfer of operatorship of such Properties, Purchaser shall obtain, or cause to be obtained in the name of Purchaser, (a) such insurance covering the Assets as would be obtained by a reasonably prudent operator in a similar situation and (b) replacements for such bonds, letters of credit and guaranties, to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guaranties posted by Sabine Parent or to consummate the transactions contemplated by this Agreement.

Section 7.8            Notification of Breaches.  Between the Execution Date and the Closing Date:

(a)           Purchaser shall notify Seller promptly after Purchaser obtains actual knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b)           Seller shall notify Purchaser promptly after Seller obtains actual knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c)           If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue in any material respect between the Execution Date and the Closing Date, or

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if any of Purchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing (or, if the Closing does not occur, by the date set forth in Section 9.1), then such breach shall be considered not to have occurred for all purposes of this Agreement.

Section 7.9            Amendment to Schedules.  As of the Closing Date, all Schedules to this Agreement, as applicable, shall be deemed amended and supplemented by Seller to include reference to any matter which results in an adjustment to the Purchase Price pursuant to Section 3.3 as a result of the removal under the terms of this Agreement of any of the Assets.

Section 7.10          Release of Liens.  Concurrent with Closing, except for Permitted Encumbrances, all liens, charges, mortgages and security interests (if any) encumbering any of the Assets that arise under any debt facilities maintained by Seller or any of its Affiliates shall be terminated.

Section 7.11          Hedges.  At or prior to Closing, Seller and its Affiliates shall eliminate all futures, options, swaps or other derivatives (if any) with respect to the sale of production from the Assets that are currently binding on the Assets or will be binding on the Assets after Closing.

Section 7.12          Further Assurances.  After Closing, Seller and Purchaser agree to take such further actions and to execute, acknowledge and deliver all such further documents as are reasonably requested by the other Party for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

Section 7.13          Financial Statements.  Seller acknowledges that Purchaser and its Affiliates may be required to include statements of revenues and direct operating expenses and other financial information relating to the transactions contemplated by this Agreement in documents filed by Purchaser and its Affiliates with the Securities Exchange Commission (the “SEC”) pursuant to the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and that such financial statements may be required to be audited.  Accordingly, from and after the Execution Date, Seller shall use commercially reasonable efforts to (a) provide Purchaser with such information currently in Seller’s possession about the Assets as may be reasonably required to be included in the documents filed by Purchaser and its Affiliates with the SEC (the “SEC Documents”), (b) provide, and shall cause its Affiliates, officers and employees to provide, reasonable cooperation in connection with the preparation of such SEC Documents (to the extent possible), including providing reasonable access to auditors, auditor work papers, employees, books and records, and any financial data reasonably requested by Purchaser in connection therewith, and (c) cause its independent public accountants to provide any consent necessary for the filing of the SEC Documents and to deliver a customary comfort letter to Purchaser (in each case, at Purchaser’s expense and to the extent possible) with respect to financial information relating to the transactions contemplated by this Agreement included as part of such SEC Documents.  Within two (2) Business Days following the Execution Date, Purchaser will file a request with the SEC for the SEC Waiver and, thereafter, take all actions that are commercially reasonable in order to obtain such waiver.  Notwithstanding the foregoing, if Purchaser does not obtain the SEC Waiver, Seller shall use commercially reasonable efforts to assist Purchaser in obtaining, and Purchaser shall use

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commercially reasonable efforts to obtain, such additional information about the Assets as may be reasonably required to be included in the SEC Documents, whether or not such information is currently in Seller’s possession.

ARTICLE 8
CONDITIONS TO CLOSING

Section 8.1            Seller’s Conditions to Closing.  The obligations of Seller to consummate the transactions contemplated by this Agreement are subject to Seller’s rights under Section 4.5(d) and the satisfaction (or waiver by Seller) on or prior to Closing of each of the following conditions precedent:

(a)           Representations.  The representations and warranties of Purchaser set forth in Article 6 shall be true and correct in all material respects as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date; provided, however, that (i) any representation or warranty referring to a specified date need only be true and accurate as of such specified date, and (ii), to the extent a representation or warranty is qualified by its terms by materiality, such qualification in its terms is inapplicable for purposes of this Section and the materiality qualification contained in this Section 8.1(a) applies in lieu thereof;

(b)           Performance.  Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           No Action.  No injunction, order or award restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated by this Agreement, or granting material damages in connection therewith, shall have been issued and remain in force, and no suit, action or other proceeding by a Third Party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, or seeking substantial damages in connection therewith, shall be pending before any Governmental Body or arbitrator; and

(d)           Governmental Consents.  All consents and approvals of any Governmental Body required for the transfer of the Assets from Seller to Purchaser as contemplated under this Agreement, except consents and approvals by Governmental Bodies that are customarily obtained after closing (including Customary Post-Closing Consents), shall have been granted, or the necessary waiting period shall have expired, or early termination of the waiting period shall have been granted.

Section 8.2            Purchaser’s Conditions to Closing.  The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject to the satisfaction (or waiver by Purchaser) on or prior to Closing of each of the following conditions precedent:

(a)           Representations.  The representations and warranties of Seller set forth in Article 5 shall be true and correct in all material respects as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date; provided, however, that (i) any representation or warranty referring to a specified date need only be true and accurate as of such specified date, and (ii), to the extent a representation or warranty is qualified by its terms by

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materiality, such qualification in its terms is inapplicable for purposes of this Section and the materiality qualification contained in this Section 8.2(a) applies in lieu thereof;

(b)           Performance.  Seller shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           No Action.  No injunction, order or award restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated by this Agreement, or granting material damages in connection therewith, shall have been issued and remain in force, and no suit, action or other proceeding by a Third Party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, or seeking substantial damages in connection therewith, shall be pending before any Governmental Body or arbitrator;

(d)           Governmental Consents.  All consents and approvals of any Governmental Body required for the transfer of the Assets from Seller to Purchaser as contemplated under this Agreement, except consents and approvals by Governmental Bodies that are customarily obtained after closing (including Customary Post-Closing Consents), shall have been granted, or the necessary waiting period shall have expired, or early termination of the waiting period shall have been granted;

(e)           Hedges.  All hedges described in Section 7.11 shall have terminated;

(f)            Liens.  Seller shall have delivered or caused to be delivered to Purchaser customary documentation or evidence providing for the release, prior to or in connection with Closing, of all liens on or security interests described in Section 7.10; and

(g)           Financial Information.  Purchaser shall have received reasonable assurances from the SEC that Purchaser may satisfy its obligations to provide audited financial information relating to the transactions contemplated by this Agreement by providing audited statements of revenues and direct operating expenses for the Assets for the period from January 1, 2013 through the Closing in lieu of providing audited financial statements for the Assets for the year ended December 31, 2012 (the “SEC Waiver”) or, if Purchaser has not received the SEC Waiver, Purchaser shall have received access to all information about the Assets as may be reasonably required to provide audited financial statements for the year ended December 31, 2012; provided, however, that in the event that neither of the preceding requirements described in this Section 8.2(g) has been satisfied or waived as of 5 p.m., Central Time, December 27, 2013, then (i) the closing condition in this Section 8.2(g) shall be deemed satisfied as of such date and, (ii) if all of the other conditions in Article 8 to be satisfied prior to Closing have been satisfied or waived, the Parties will, pursuant to Section 9.1(a), consummate the purchase and sale transaction contemplated by this Agreement at 11:59 p.m., Central Time, on December 31, 2013.

ARTICLE 9
CLOSING

Section 9.1            Time and Place of Closing.  Consummation of the purchase and sale transaction as contemplated by this Agreement (the “Closing”), shall, unless otherwise agreed to

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in writing by Purchaser and Seller, take place at the offices of Seller, at 10:00 a.m., Central Time, on December 18, 2013, or if all conditions in Article 8 to be satisfied prior to Closing have not yet been satisfied or waived as of such time, then, (a) in the event that all such conditions are satisfied or waived prior to January 1, 2014, the Closing shall occur on December 31, 2013 (as of 11:59 p.m., Central Time, if the circumstance described in the proviso in Section 8.2Section 8.2(g) is the case) or (b) in the event that all such conditions are satisfied or waived on or after January 1, 2014, within five (5) Business Days of such conditions having been satisfied or waived, subject, in each case, to the rights of the Parties under Article 10.  The date on which the Closing occurs is herein referred to as the “Closing Date.”

Section 9.2            Obligations of Seller at Closing.  At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by Purchaser of its obligations pursuant to Section 9.3, Seller shall deliver or cause to be delivered to Purchaser the following:

(a)           Counterparts of the Conveyances of the Assets, in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by Seller and acknowledged before a notary public;

(b)           Counterparts of the Letter-in-lieu of Transfer Order covering the relevant Assets, duly executed by Seller;

(c)           A certificate duly executed by an authorized officer of Seller, dated as of Closing, certifying on behalf of Seller that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(d)           An executed statement conforming to the reasonable satisfaction of Purchaser, meeting each of the requirements described in Treasury Regulation § 1.1445-2(b)(2), certifying that Seller is not a foreign person within the meaning of the Code;

(e)           Where approvals are received by Seller pursuant to a filing or application under Section 7.2, copies of those approvals;

(f)            Counterparts of the Escrow Agreement, duly executed by Seller;

(g)           The notices described in Section 7.5; and

(h)           All other instruments, documents and other items reasonably necessary to effectuate the terms of this Agreement, as may be reasonably requested by Purchaser.

Section 9.3            Obligations of Purchaser at Closing.  At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by Seller of its obligations pursuant to Section 9.2, Purchaser shall deliver or cause to be delivered to Seller items (a)-(g)and (i)and, to the Escrow Agent, item (h)below:

(a)           A wire transfer of the Closing Payment to the accounts designated by Seller in immediately available funds;

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(b)           Counterparts of the Conveyances of the Assets, in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by Purchaser and acknowledged before a notary public;

(c)           Counterparts of the Letter-in-lieu of Transfer Order covering the relevant Assets, duly executed by Purchaser;

(d)           A certificate by an authorized officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled;

(e)           Where approvals are received by Purchaser pursuant to a filing or application under Section 7.2, copies of those approvals;

(f)            Evidence of replacement bonds, guaranties and letters of credit pursuant to Section 7.7;

(g)           Counterparts of the Escrow Agreement, duly executed by Purchaser;

(h)           Purchaser shall have delivered or caused to be delivered to the Escrow Agent the Escrow Amount pursuant to Section 4.2(c) and Section 4.2(d), as applicable; and

(i)            All other instruments, documents and other items reasonably necessary to effectuate the terms of this Agreement, as may be reasonably requested by Seller.

Section 9.4            Closing Payment and Post-Closing Purchase Price Adjustments.

(a)           Not later than five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Purchaser, using and based upon the best information available to Seller, a preliminary settlement statement estimating the initial Adjusted Purchase Price after giving effect to all Purchase Price adjustments set forth in Section 3.3.  The estimate delivered in accordance with this Section 9.4(a) less the Deposit shall constitute the Dollar amount to be paid by Purchaser to Seller at the Closing (the “Closing Payment”).

(b)           Following the Closing, Seller shall prepare and deliver to Purchaser a statement setting forth the final calculation of the Adjusted Purchase Price and showing the calculation of each adjustment, based, to the extent possible, on actual credits, charges, receipts and other items before and after the Effective Time no later than the later of (x) the 90th day following the Closing Date and (y) the date on which the Parties or the Title Arbitrator, as applicable, finally determines all Title Defect Amounts and Title Benefit Amounts under Section 4.4.  Seller shall, at Purchaser’s request, supply reasonable documentation available to support any credit, charge, receipt or other item included in such statement.  Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to Seller’s statement no later than the later of: (i) the 90th day following Purchaser’s receipt thereof or (ii) May 31, 2014.  Seller may deliver a written report to Purchaser during this same period reflecting any changes that Seller proposes to be made to such statement as a result of additional information received after the statement was prepared.  The Parties shall undertake to agree on the final statement of the Adjusted Purchase Price no later than 225 days after the Closing Date;

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provided, however, that if the date on which the Parties or the Title Arbitrator, as applicable, finally determines all Title Defect Amounts and Title Benefit Amounts under Section 4.4 is later than the 90th day following the Closing Date, such 225 day period shall be extended the same number of days that such final determination occurs beyond the 90th day following the Closing Date (such date, as extended, the “Cut-off Date”).  In the event that the Parties cannot reach agreement within such period of time, either Party may refer the remaining matters in dispute to the Houston office of a mutually-agreed accounting firm for review and final determination by arbitration.  The accounting firm shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section.  The accounting firm’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both Parties, without right of appeal.  In determining the proper amount of any adjustment to the Unadjusted Purchase Price, the accounting firm shall not increase the Unadjusted Purchase Price more than the increase proposed by Seller nor decrease the Unadjusted Purchase Price more than the decrease proposed by Purchaser, as applicable.  The accounting firm shall act as an expert for the limited purpose of determining the specific disputed matters submitted by the Parties and may not award damages or penalties to the Parties with respect to any matter.  Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case.  Seller shall bear one-half and Purchaser shall bear one-half of the costs and expenses of the accounting firm.  Within ten (10) days after the earlier of (i) the expiration of Purchaser’s 60-day review period without delivery of any written report or (ii) the date on which the Parties finally determine the Adjusted Purchase Price or the accounting firm finally determines the disputed matters, as applicable, (A) Purchaser shall pay to Seller the amount by which the Adjusted Purchase Price (after deducting the Deposit amount) exceeds the Closing Payment or (B) Seller shall pay to Purchaser the amount by which the Closing Payment exceeds the Adjusted Purchase Price (after deducting the Deposit amount), as applicable.  Any post-closing payment pursuant to this Section 9.4(b) shall bear interest from the Closing Date to the date of payment at the Prime Rate.

(c)           Purchaser shall assist Seller in the preparation of the final statement of the Adjusted Purchase Price under Section 9.4(b) by furnishing invoices, receipts, reasonable access to personnel and such other assistance as may be requested by Seller to facilitate such process post-Closing.

(d)           All payments made or to be made under this Agreement to Seller shall be made by electronic transfer of immediately available funds to the accounts designated by Seller.  All payments made or to be made hereunder to Purchaser shall be by electronic transfer or immediately available funds to a bank and account specified by Purchaser in writing to Seller.

ARTICLE 10
TERMINATION

Section 10.1          Termination.  This Agreement may be terminated at any time prior to Closing: (a) by the mutual prior written consent of Seller and Purchaser; (b) by Seller if Purchaser has not delivered the Deposit to Seller by 5:00 p.m. Central Time on the Execution Date pursuant to Section 3.1; (c) by either Purchaser or Seller if Closing has not occurred prior to January 1, 2014; provided, however, that no Party shall be entitled to terminate this Agreement

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under Section 10.1(c) if the Closing has failed to occur because such Party negligently or willfully failed to perform or observe in any material respect its covenants or agreements hereunder; (d) by either Purchaser or Seller under Section 4.5(d), if applicable; or (e) automatically, without any further action of the Parties, in the event that Seller pays Purchaser the Hedges Termination Payment pursuant to Section 10.4.

Section 10.2          Effect of Termination.  If this Agreement is terminated pursuant to Section 10.1, this Agreement shall become void and of no further force or effect (except for the provisions of Section 5.6, Section 6.5, Section 7.1(e), Section 7.3, this Article 10, Article 13 (other than Section 13.1, Section 13.3, Section 13.12 and Section 13.15) and Appendix A, which shall continue in full force and effect) and, without prejudice to its rights under Section 10.3(a) (if applicable), Seller shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement.  Notwithstanding anything to the contrary in this Agreement, the termination of this Agreement under Section 10.1 shall not relieve either Party, subject to Section 10.4 and Section 13.11, from liability for any willful or negligent failure to perform or observe in any material respect any of its agreements or covenants contained herein which are to be performed at or prior to Closing.

Section 10.3          Distribution of Deposit Upon Termination.

(a)           If Seller terminates this Agreement under Section 10.1(c), and (i) at the time of termination Purchaser has negligently or willfully failed to perform or observe its covenants and agreements or is in breach of its representations and warranties hereunder, (ii) all conditions of Purchaser to Closing have been fulfilled (other than the conditions (A) set forth in Section 8.2(e) and Section 8.2(f) or (B) for which Seller has not been able to fulfill or otherwise satisfy based on Purchaser’s negligent or willful failure to perform or observe its covenants and agreements hereunder) and (iii) Seller is ready, willing and able to close (subject to the preceding parenthetical), then Seller shall be entitled, as liquidated damages for lost opportunities (and not as a penalty), to retain the Deposit together with any interest or income thereon, free of any claims by Purchaser or any other Person.

(b)           If this Agreement is terminated for any reason other than the reasons set forth in Section 10.3(a), Seller shall deliver to Purchaser the Deposit and any interest accrued thereon, free of any claims by Seller or any other Person with respect thereto.

Section 10.4          Purchaser Hedges.  Seller acknowledges that in connection with the execution and delivery of this Agreement Purchaser will be entering into hedging transactions at current NYMEX strip prices for the quantities of hydrocarbons set forth in Schedule 10.4 (the “Purchaser Hedges”). In the event that (i) on the Closing Date all conditions of Seller to Closing have been fulfilled or waived (and Purchaser is ready, willing and able to close) and Seller fails or refuses to close (and Seller is not otherwise entitled to terminate this Agreement) (such event, a “Seller Closing Failure”) and (ii) Purchaser either does not seek, or does not prevail on a claim for, specific performance pursuant to Section 13.17, Seller shall pay to Purchaser (in addition to any other damages that Purchaser may be entitled to receive) the aggregate costs, if any, to Purchaser for the termination or unwinding of the Purchaser Hedges (the “Hedges Termination Payment”), in which event, this Agreement will automatically terminate pursuant to Section 

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10.1(e) without any further action of the Parties.  Notwithstanding anything to the contrary herein, in no event will Seller’s liability (including the payment of the Hedges Termination Payment and any other damages to which Purchaser may be entitled) under this Agreement for the termination of this Agreement due to a Seller Closing Failure exceed five percent (5%) of the Unadjusted Purchase Price.

ARTICLE 11
 ASSUMPTION; INDEMNIFICATION

Section 11.1          Assumption by Purchaser, Retention by Seller.  Without limiting Purchaser’s rights to indemnity under Section 11.2 and Purchaser’s remedy for Title Defects in Article 4, Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be timely fulfilled, performed, paid or discharged) all of the Assumed Purchaser Obligations.

(a)           “Assumed Purchaser Obligations” shall mean all obligations and liabilities (including Environmental Liabilities), known or unknown, with respect to or arising from the Assets on or after the Effective Time (except as set forth in clauses (iii)-(vi) below), including obligations and liabilities relating in any manner to the condition, use, ownership or operation of the Assets, including obligations to (i) furnish makeup gas and settle Imbalances attributable to the Assets according to the terms of applicable gas sales, processing, gathering or transportation Contracts, (ii) pay working interests, royalties, overriding royalties and other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons produced from the Assets, (iii) the matters that are the bases for the downward adjustments set forth in Section 3.3(b) (irrespective of whether such matters arose prior to, on or after the Effective Time, but, in each case, without prejudice to Purchaser’s rights hereunder to an adjustment to the Purchase Price at the Closing or pursuant to Section 9.4(b)); provided that Purchaser actually receives a downward adjustment to the Purchase Price in respect of same, (iv) pay the proportionate share attributable to the Assets to properly plug and abandon any and all Wells, including temporarily abandoned Wells, (v) pay the proportionate share attributable to the Assets to dismantle or decommission and remove any property and other property of whatever kind related to or associated with operations and activities conducted by whomever on the Assets, (vi) pay the proportionate share attributable to the Assets to abandon, clean up, restore and/or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Laws and (vii) pay the proportionate share attributable to the Assets to perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and the Contracts, or as required by any Law and the matters set forth on Schedule 11.1 (if any); but excluding, in all such instances, (A) matters that are subject to indemnification pursuant to Section 11.2(b)(ii)-(vi), (B) all Taxes for which Seller is responsible hereunder, (C) matters that are attributable or arise out of the Excluded Assets, and (D) matters that are caused by, arise out of, or result from off-site disposal of any substance defined or regulated as a “pollutant”, “hazardous waste” or “hazardous substance” under any Environmental Law, to the extent that such disposal occurred during Seller’s ownership of the Assets.

(b)           Except for the Assumed Purchaser Obligations, Purchaser shall not assume or otherwise become liable for any liabilities, Damages, duties or other obligations of Seller, whether or not relating to the Assets, whether absolute, contingent, or otherwise, whether

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known or unknown, accrued or unaccrued, and regardless of whether such liability, Damage, duty, or other obligation was disclosed to Purchaser, including any liabilities, Damages, duties, or obligations that relate to the ownership or operation of the Assets prior to the Effective Time (collectively, subject to such exception, the “Retained Seller Obligations”).

Section 11.2          Indemnification.

(a)           From and after Closing, except for matters for which Seller is obligated to indemnify Purchaser under Section 11.2(b), Purchaser shall indemnify, defend and hold harmless the Seller Group from and against all Damages incurred, suffered by or asserted against such Persons:

(i)            caused by or arising out of or resulting from the Assumed Purchaser Obligations;

(ii)           caused by or arising out of or resulting from Purchaser’s breach of any of Purchaser’s covenants or agreements contained in Article 7; or

(iii)          caused by or arising out of or resulting from any breach of any representation or warranty made by Purchaser contained in Article 6 or in the certificate delivered by Purchaser at Closing pursuant to Section 9.3(d);

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF THE SELLER GROUP.

(b)           From and after Closing, Seller shall indemnify, defend and hold harmless the Purchaser Group from and against all Damages incurred, suffered by or asserted against such Persons:

(i)            caused by or arising out of or resulting from the Retained Seller Obligations (excluding any Retained Seller Obligations that also constitute matters covered by the representations and warranties made by Seller in Article 5, which will be subject to indemnification pursuant to Section 11.2(b)(v));

(ii)           attributable to or arising out of the Excluded Assets;

(iii)          caused by, arising out of or resulting from off-site disposal of any substance defined or regulated as a “pollutant”, “hazardous waste” or “hazardous substance” under any Environmental Law, to the extent that such disposal occurred during Seller’s ownership of the Assets;

(iv)          caused by or arising out of or resulting from Seller’s breach of any of Seller’s covenants or agreements contained in Article 7;

(v)           caused by or arising out of our resulting from any breach of any representation or warranty made by Seller contained in Article 5 or in the certificate delivered by Seller at Closing pursuant to Section 9.2(c);

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(vi)          attributable to or arising out of any Tax obligations retained by Seller pursuant to Article 12; or

(vii)         caused by or arising out of or resulting from the litigation listed on Schedule 11.2(b)(vii).

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF THE PURCHASER GROUP.

(c)           Notwithstanding anything to the contrary contained in this Agreement, from and after the Closing, this Section 11.2 contains the Parties’ exclusive remedies against each other with respect to breaches of the representations, warranties, covenants and agreements of the Parties in Article 5, Article 6 and Article 7 and the affirmations of such representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Section 9.2(c) or Section 9.3(d), as applicable.  Except for the remedies contained in this Section 11.2, Section 10.2, Section 10.3 and Section 13.17, and any other remedies available to the Parties at law or in equity for breaches of provisions of this Agreement other than Article 5, Article 6 and Article 7, SELLER AND PURCHASER EACH RELEASE, REMISE AND FOREVER DISCHARGE THE OTHER PARTY AND ITS AFFILIATES AND ALL SUCH PARTIES’ OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ADVISORS AND OTHER REPRESENTATIVES FROM ANY AND ALL SUITS, LEGAL OR ADMINISTRATIVE PROCEEDINGS, CLAIMS, DEMANDS, DAMAGES, LOSSES, COSTS, LIABILITIES, INTEREST, OR CAUSES OF ACTION WHATSOEVER, IN LAW OR IN EQUITY, KNOWN OR UNKNOWN, WHICH SUCH PARTIES MIGHT NOW OR SUBSEQUENTLY MAY HAVE, BASED ON, RELATING TO OR ARISING OUT OF (i) THIS AGREEMENT, (ii) SELLER’S AND SABINE PARENT’S (AS APPLICABLE) OWNERSHIP, USE OR OPERATION OF THE ASSETS OR (iii) THE CONDITION, QUALITY, STATUS OR NATURE OF THE ASSETS, INCLUDING RIGHTS TO CONTRIBUTION UNDER CERCLA OR ANY OTHER ENVIRONMENTAL LAW, BREACHES OF STATUTORY OR IMPLIED WARRANTIES, NUISANCE OR OTHER TORT ACTIONS, RIGHTS TO PUNITIVE DAMAGES AND COMMON LAW RIGHTS OF CONTRIBUTION, RIGHTS UNDER AGREEMENTS BETWEEN SELLER AND ANY PERSONS WHO ARE AFFILIATES OF SELLER, AND RIGHTS UNDER INSURANCE MAINTAINED BY SELLER OR ANY PERSON WHO IS AN AFFILIATE OF SELLER, EVEN IF CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY RELEASED PERSON, EXCEPT FRAUD.

(d)           The indemnity of each Party provided in this Section 11.2 shall be for the benefit of and extend to each Person included in the Seller Group and the Purchaser Group, as applicable; provided, however, that any claim for indemnity under this Section 11.2 by any such Person must be brought and administered by a Party to this Agreement.  No Indemnified Person (including any Person within the Seller Group and the Purchaser Group) other than Seller and Purchaser shall have any rights against either Seller or Purchaser under the terms of this Section 11.2 except as may be exercised on its behalf by Purchaser or Seller, as applicable, pursuant to

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this Section 11.2(d).  Seller and Purchaser may elect to exercise or not exercise indemnification rights under this Section on behalf of the other Indemnified Persons affiliated with it in its sole discretion and shall have no liability to any such other Indemnified Person for any action or inaction under this Section.

Section 11.3          Indemnification Actions.  All claims for indemnification under Section 11.2 shall be asserted and resolved as follows:

(a)           For purposes hereof, (i) the term “Indemnifying Person” when used in connection with particular Damages shall mean the Person or Persons having an obligation to indemnify another Person or Persons with respect to such Damages pursuant to this Article 11 and (ii) the term “Indemnified Person” when used in connection with particular Damages shall mean the Person or Persons having the right to be indemnified with respect to such Damages by another Person or Persons pursuant to this Article 11.

(b)           To make a claim for indemnification under Section 11.2, an Indemnified Person shall notify the Indemnifying Person of its claim under this Section 11.3, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”).  In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Person (a “Third Party Claim”), the Indemnified Person shall provide its Claim Notice promptly after the Indemnified Person has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Person to give notice of a Third Party Claim as provided in this Section 11.3 shall not relieve the Indemnifying Person of its obligations under Section 11.2 except to the extent such failure results in insufficient time being available to permit the Indemnifying Person to effectively defend against the Third Party Claim or otherwise prejudices the Indemnifying Person’s ability to defend against the Third Party Claim.  In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement which was inaccurate or breached.

(c)           In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Person shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Person whether it admits or denies its obligation to defend the Indemnified Person against such Third Party Claim under this Article 11.  If the Indemnifying Person does not notify the Indemnified Person within such 30-day period whether the Indemnifying Person admits or denies its obligation to defend the Indemnified Person, it shall be conclusively deemed to have denied such indemnification obligation hereunder.  The Indemnified Person is authorized, prior to and during such 30-day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Person and that is not prejudicial to the Indemnifying Person.

(d)           If the Indemnifying Person admits its obligation, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Third Party Claim.  The Indemnifying Person shall have full control of such defense and proceedings, including any compromise or settlement thereof.  If requested by the Indemnifying Person, the Indemnified Person agrees to cooperate in contesting any Third Party Claim which the Indemnifying Person

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elects to contest (provided, however, that the Indemnified Person shall not be required to bring any counterclaim or cross-complaint against any Person).  The Indemnified Person may at its own expense participate in, but not control, any defense or settlement of any Third Party Claim controlled by the Indemnifying Person pursuant to this Section 11.3(d).  An Indemnifying Person shall not, without the written consent of the Indemnified Person, settle any Third Party Claim or consent to the entry of any judgment with respect thereto which (i) does not result in a final resolution of the Indemnified Person’s liability with respect to the Third Party Claim (including, in the case of a settlement, an unconditional written release of the Indemnified Person) or (ii) may materially and adversely affect the Indemnified Person (other than as a result of money damages covered by the indemnity).

(e)           If the Indemnifying Person does not admit its obligation or admits its obligation but fails to diligently defend or settle the Third Party Claim, then the Indemnified Person shall have the right to defend against the Third Party Claim (at the sole cost and expense of the Indemnifying Person, if the Indemnified Person is entitled to indemnification hereunder), with counsel of the Indemnified Person’s choosing, subject to the right of the Indemnifying Person to admit its obligation and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof.  If the Indemnifying Person has not yet admitted its obligation to provide indemnification with respect to a Third Party Claim, the Indemnified Person shall send written notice to the Indemnifying Person of any proposed settlement and the Indemnifying Person shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its obligation to provide indemnification with respect to the Third Party Claim and (ii) if its obligation is so admitted, reject, in its reasonable judgment, the proposed settlement.  If the Indemnified Person settles any Third Party Claim over the objection of the Indemnifying Person after the Indemnifying Person has timely admitted its obligation in writing and assumed the defense of a Third Party Claim, the Indemnified Person shall be deemed to have waived any right to indemnity therefor.

(f)            In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Person shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Damages complained of, (ii) admit its obligation to provide indemnification with respect to such Damages or (iii) dispute the claim for such indemnification.  If the Indemnifying Person does not notify the Indemnified Person within such 30-day period that it has cured the Damages or that it disputes the claim for such indemnification, the Indemnifying Person shall be deemed to have disputed such claim for indemnification hereunder.

Section 11.4          Limitation on Actions.

(a)           The representations and warranties of the Parties in Article 5 and Article 6 and the corresponding representations and warranties given in the certificates delivered at Closing pursuant to Section 9.2(c) and Section 9.3(d), as applicable, shall survive the Closing for a period of twelve (12) months (unless a shorter period is expressly provided within the applicable Section), except that (i) the representations, warranties and acknowledgements, as applicable, in Section 5.2, Section 5.3, Section 5.4, Section 5.5, Section 5.6, Section 6.1, Section 6.2, Section 6.3, Section 6.4, Section 6.5, Section 6.8, Section 6.9 and Section 6.13 shall survive indefinitely, and (ii) the representations and warranties in Section 5.10 shall survive Closing until sixty (60) days after the applicable statute of limitations closes the taxable year to which the

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subject Taxes relate. Covenants and agreements of the Parties contained herein (except for Article 12) shall survive the Closing until fully performed. The remainder of this Agreement (including the disclaimers in Section 5.21) shall survive the Closing without time limit except (A) as may otherwise be expressly provided herein and (B) for the provisions of Article 12, which shall survive Closing until sixty (60) days after the applicable statute of limitations closes the taxable year to which the subject Taxes relate.  Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration, provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b)           The indemnity obligations in Section 11.2(a)(ii), Section 11.2(a)(iii), Section 11.2(b)(iv) and Section 11.2(b)(v) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification thereunder, except in each case as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Person on or before such termination date. The indemnity obligations of Seller in Section 11.2(b)(i) and Section 11.2(b)(iii) shall terminate on the date that is twelve (12) months following the Closing Date. The indemnity obligations of Seller pursuant to Section 11.2(b)(vi) shall survive Closing until sixty (60) days after the applicable statute of limitations closes the taxable year to which the subject Taxes relate.  The indemnity obligations of Seller pursuant to Section 11.2(b)(vii) shall terminate on the date on which (i) a final, non-appealable judgment is entered on or (ii) the appropriate Persons enter into a settlement agreement which fully and finally resolves, in either case, all litigation set forth on Schedule 11.2(b)(vii).  The indemnity obligations of Seller pursuant to Section 11.2(b)(ii) and the indemnity obligations of Purchaser in Section 11.2(a)(i) shall continue without time limit.

(c)           Except with respect to the representations, warranties, acknowledgements, and covenants, as applicable, under Sections 5.2, 5.3, 5.4, 5.5, 5.6, 5.10 and Article 12, which shall not be subject to this Section 11.4(c), Seller shall not have any liability for any indemnification under Section 11.2(b)(i), Section 11.2(b)(iv) or Section 11.2(b)(v) until and unless the aggregate amount of the liability for all Damages for which Claim Notices are delivered by Purchaser exceeds two percent (2%) of the Unadjusted Purchase Price, and then only to the extent such Damages, in the aggregate, exceed two percent (2%) of the Unadjusted Purchase Price; provided that for the purposes of making the determination of whether the Damages for which Claim Notices are delivered by Purchaser exceeds two percent (2%) of the Unadjusted Purchase Price, any representation or warranty set forth in this Agreement that is qualified by materiality shall be deemed not to be so qualified.

(d)           Except with respect to Seller’s indemnity obligations in respect of (i) the representations, warranties, acknowledgements and covenants, as applicable, under Sections 5.2, 5.3, 5.4, 5.5, 5.6, 5.10, 7.3, 7.10, 7.11 and Article 12 or the special warranty of title in the Conveyance, and (ii) Section 11.2(b)(ii), Section 11.2(b)(iii), Section 11.2(b)(vi) and Section 11.2(b)(vii), none of which shall be subject to this Section 11.4(d), Seller shall not be required to indemnify the Purchaser Group under this Article 11 for aggregate Damages in excess of fifteen percent (15%) of the Unadjusted Purchase Price.

(e)           The amount of any Damages for which an Indemnified Person is entitled to indemnity under this Article 11 shall be reduced by the amount of insurance proceeds realized

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by the Indemnified Person or its Affiliates with respect to such Damages (net of any collection costs, and excluding the proceeds of any insurance policy issued or underwritten by the Indemnified Person or its Affiliates).

(f)            Purchaser shall not be entitled to indemnification or any other remedy under this Agreement with respect to any Damages or other liability, loss, cost, expense, claim, award or judgment attributable to or arising out of the actions of Purchaser as operator of any of the Properties.

(g)           In no event shall (i) any Indemnified Person be entitled to duplicate compensation with respect to the same Damage, liability, loss, cost, expense, claim, award or judgment under more than one provision of this Agreement and the various documents delivered in connection with the Closing, and (ii) any Person be entitled to indemnification hereunder with respect to a breach by an Indemnifying Person of any of the representations, warranties or covenants made or agreed to by such Indemnifying Person hereunder of which such Person had actual knowledge prior to the Closing Date.

ARTICLE 12
TAX MATTERS

Section 12.1          Tax Filings.  From the Effective Time through the Closing Date, Seller shall be responsible for filing with the appropriate Governmental Body the applicable Tax Returns for Asset Taxes which are required to be filed on or before the Closing Date and paying the Taxes reflected on such Tax Returns as due and owing (provided that to the extent such Taxes relate to the periods from and after the Effective Time, as determined pursuant to Section 12.2, such payment shall be on behalf of Purchaser, and promptly following the Closing Date, following Seller’s request, Purchaser shall pay to Seller any such Taxes; but only to the extent that such amounts have not already been accounted for under Section 3.3).  Purchaser shall be responsible for the filing with the appropriate taxing authorities the applicable Tax Returns for all Asset Taxes that are required to be filed after the Closing Date and paying the Taxes reflected on such Tax Returns as due and owing; provided, however, that in the event that Seller is required by applicable Tax Law to file a Tax Return with respect to such Asset Taxes after the Closing Date which includes all or a portion of a Tax period for which Purchaser is liable for such Taxes, following Seller’s request, Purchaser shall promptly pay to Seller all such Taxes allocable to the period or portion thereof beginning at or after the Effective Time (but only to the extent that such amounts have not already been accounted for under Section 3.3), whether such Taxes arise out of the filing of an original return or a subsequent audit or assessment of Taxes.  Seller shall be entitled to all Tax credits and Tax refunds which relate to any such Taxes allocable to any Tax period, or portion thereof, ending before the Effective Time.

Section 12.2          Current Tax Period Taxes.  Asset Taxes assessed with respect to the Tax period in which the Effective Time occurs (the “Current Tax Period”), but excluding ad valorem, property, severance production or similar Taxes which are based on quantity of or the value of production of Hydrocarbons, shall be apportioned between Seller and Purchaser as of the Effective Time with (a) Seller being obligated to pay a proportionate share of the actual amount of such Taxes for the Current Tax Period determined by multiplying such actual Taxes by a fraction, the numerator of which is the number of days in the Current Tax Period prior to the

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Effective Time and the denominator of which is the total number of days in the Current Tax Period and (b) Purchaser being obligated to pay a proportionate share of the actual amount of such Taxes for the Current Tax Period determined by multiplying such actual Taxes by a fraction, the numerator of which is the number of days in the Current Tax Period on and after the date of the Effective Time and the denominator of which is the total number of days in the Current Tax Period.  As described in Section 2.4(f), Asset Taxes which are based on quantity of or the value of production of Hydrocarbons shall be apportioned between Seller and Purchaser based on the number of units or value of production actually produced, as applicable, before, and at or after, the Effective Time and (ii) all other Asset Taxes which are imposed on the sale, purchase or transfer of tangible property (other than the sale of the Assets as provided in this Agreement) shall be apportioned between Seller and Purchaser based on the applicable date of sale, purchase or transfer.  In the event that Purchaser or Seller makes any payment for which it is entitled to reimbursement under this Article 12, the applicable Party shall make such reimbursement promptly but in no event later than ten (10) days after the presentation of a statement setting forth the amount of reimbursement to which the presenting Party is entitled along with such supporting evidence as is reasonably necessary to calculate the amount of the reimbursement.

Section 12.3Tax Reimbursement.  If, prior to Closing, Seller has paid on behalf of other working interest owners, royalty interest owners, overriding royalty interest owners and other interest owners in the Assets, ad valorem, property, severance, production and similar Taxes imposed on the ownership of the Assets or the production of Hydrocarbons produced from such Assets for Tax periods or portions thereof after the Effective Time (such amounts, “Post-Effective Time Tax Advances”) and has not recouped such Post-Effective Time Tax Advances before the Closing Date from such working interest owners, royalty interest owners, overriding royalty interest owners and other interest owners in the Assets, Purchaser shall use its commercially reasonable efforts to recoup the Post-Effective Time Tax Advances from such other working interest owners, royalty interest owners, overriding royalty interest owners and other interest owners in such Assets and shall promptly remit any such recovered Post-Effective Time Tax Advance amounts to Seller.

Section 12.4Characterization of Certain Payments.  The Parties agree that any payments made pursuant to this Article 12, Article 11, Section 2.4 or Section 9.4 shall be treated for all Tax purposes as an adjustment to the Purchase Price unless otherwise required by Law.

Section 12.5Tax-Deferred Exchange.  Either Party may elect to effect a tax-deferred exchange under Section 1031 of the Code (a “Tax Deferred Exchange”) for all or part of the Assets at any time prior to the Closing Date.  If a Party elects to effect a Tax Deferred Exchange (the “Electing Party”), the other Party (the “Non-electing Party”) agrees to execute escrow instructions, documents, agreements or instruments to effect the Tax Deferred Exchange and otherwise use its commercial best efforts to cooperate to carry out the Tax Deferred Exchange, provided that the Non-electing Party incurs no additional costs, expenses, fees or liabilities as a result of or connected with the Tax Deferred Exchange.  The Electing Party shall notify the Non-electing Party in writing of its intent to effect a Tax Deferred Exchange no later than three (3) days prior to the Closing Date.  In such event, the Electing Party may assign any of its rights and delegate performance of any of its duties under this Agreement in whole or in part to a “qualified intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4) of the Treasury Regulations)

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or to an “exchange accommodation titleholder” (as that term is defined in U.S. Revenue Procedure 2000-37) in order to effect such an exchange; provided, however, that the Electing Party will remain responsible to the Non-electing Party for the full and prompt performance of its delegated duties and the Closing Date shall not be delayed or affected by reason of the Tax Deferred Exchange.  Purchaser and Seller acknowledge and agree that any assignment of this Agreement (or any rights hereunder) to a qualified intermediary or exchange accommodation titleholder shall not release any Party from any of its respective liabilities and obligations hereunder and that neither Party represents to the other Party that any particular tax treatment will be given to any Party as a result thereof.  The Electing Party that assigns all or any of its rights under this Agreement pursuant to this Section 12.5 shall defend, indemnify, and hold harmless the Non-electing Party from all claims, damages, or liabilities relating to such election.

ARTICLE 13

MISCELLANEOUS

Section 13.1Counterparts.  This Agreement may be executed in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.  Either Party’s delivery of an executed counterpart signature page by facsimile (or email) is as effective as executing and delivering this Agreement in the presence of the other Party.  No Party shall be bound until such time as all of the Parties have executed counterparts of this Agreement.

Section 13.2Notice.  All notices and other communications which are required or may be given pursuant to this Agreement must be given in writing, in English and delivered personally, by courier, by telecopy or by registered or certified mail, postage prepaid, as follows:

If to Seller:

Sabine Oil & Gas LLC
1415 Louisiana St., Suite 1600
Houston, Texas 77002
Attn:  Michael Hinze
Facsimile:  (832) 242-9713

With a copy to:

Sabine Oil & Gas LLC
1415 Louisiana St., Suite 1600
Houston, Texas 77002
Attn:  Timothy Yang
Facsimile:  (713) 581-7041

If to Purchaser:

Jones Energy Holdings, LLC
807 Las Cimas Parkway, Suite 350
Austin, TX 78746
Attn:  Jody Crook

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Facsimile:  (512) 328-5394

With a copy to:

Baker Botts L.L.P.
98 San Jacinto Blvd., Suite 1500
Austin, TX 78701
Attn:  Mike Bengtson
Facsimile:  (512) 322-8349

Either Party may change its address for notice by notice to the other Party in the manner set forth above.  All notices shall be deemed to have been duly given at the time of receipt by the Party to which such notice is addressed.

Section 13.3Tax, Recording Fees, Similar Taxes & Fees.  Purchaser and Seller shall each pay and be liable for fifty percent (50%) of any sales, use, excise, real property transfer, goods and services, registration, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers or other transactions contemplated hereby.  If such transfers or transactions are exempt from any such Taxes or fees upon the execution or filing of an appropriate certificate or other evidence of exemption, Purchaser or Seller, as applicable, will timely furnish to the other Party such certificate or evidence.  Except as otherwise provided herein, all costs and expenses (including legal and financial advisory fees and expenses) incurred in connection with, or in anticipation of, this Agreement and the transactions contemplated hereby shall be paid by the Party incurring such expenses.

Section 13.4Governing Law; Jurisdiction.

(a)THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW WHICH WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION.

(b)THE PARTIES HEREBY IRREVOCABLY SUBMIT TO THE EXCLUSIVE JURISDICTION OF THE FEDERAL COURTS OF THE UNITED STATES OF AMERICA LOCATED IN HARRIS COUNTY, TEXAS (OR, IF REQUIREMENTS FOR FEDERAL JURISDICTION ARE NOT MET, STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS) AND APPROPRIATE APPELLATE COURTS THEREFROM FOR THE RESOLUTION OF ANY DISPUTE, CONTROVERSY, OR CLAIM ARISING OUT OF OR IN RELATION TO THIS AGREEMENT, AND EACH PARTY HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH DISPUTE, CONTROVERSY OR CLAIM MAY BE HEARD AND DETERMINED IN SUCH COURTS.  THE PARTIES HEREBY IRREVOCABLY WAIVE, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAWS, ANY OBJECTION WHICH THEY MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH DISPUTE,

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CONTROVERSY OR CLAIM BROUGHT IN ANY SUCH COURT OR ANY DEFENSE OF INCONVENIENT FORUM FOR THE MAINTENANCE OF SUCH DISPUTE, CONTROVERSY OR CLAIM.  EACH PARTY AGREES THAT A JUDGMENT IN ANY SUCH DISPUTE MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY APPLICABLE LAW.

(c)EACH OF THE PARTIES HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT.

Section 13.5Waivers.  Any failure by either Party to comply with any of its obligations, agreements or conditions herein contained may be waived by the Party to whom such compliance is owed by an instrument signed by such Party and expressly identified as a waiver, but not in any other manner.  No waiver of, consent to a change in, or any delay in timely exercising any rights arising from, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 13.6Assignment.  No Party shall assign all or any part of this Agreement, nor shall either Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other Party (which consent may be withheld for any reason) and any assignment or delegation made without such consent shall be void; provided, that Purchaser shall have the right to designate a wholly-owned Affiliate as the assignee under the Conveyance (in which event, for the avoidance of doubt, Purchaser will continue to be responsible for its obligations hereunder).  Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

Section 13.7Entire Agreement.  This Agreement (including, for purposes of certainty, the Appendix, Exhibits and Schedules attached hereto), the documents to be executed hereunder and the Parent Guaranty constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof.

Section 13.8Amendment.  This Agreement may be amended or modified only by an agreement in writing executed by all Parties and expressly identified as an amendment or modification.

Section 13.9No Third Party Beneficiaries.  Nothing in this Agreement shall entitle any Person other than Purchaser and Seller to any claims, cause of action, remedy or right of any kind, except the rights expressly provided in Section 7.1(e) and Section 11.2 to the Persons described therein.

Section 13.10Construction.  The Parties acknowledge that (a) Seller and Purchaser have had the opportunity to exercise business discretion in relation to the negotiation of the details of the transaction contemplated hereby, (b) this Agreement is the result of arms-length negotiations

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from equal bargaining positions and (c) Seller and Purchaser and their respective counsel participated in the preparation and negotiation of this Agreement.  Any rule of construction that a contract be construed against the drafter shall not apply to the interpretation or construction of this Agreement.

Section 13.11Limitation on Damages.  NOTWITHSTANDING ANYTHING TO THE CONTRARY, EXCEPT FOR THE HEDGES TERMINATION PAYMENT, IF APPLICABLE, AND FOR CLAIMS IN CONNECTION WITH ANY DAMAGES INCURRED BY THIRD PARTIES FOR WHICH INDEMNIFICATION IS SOUGHT UNDER THE TERMS OF THIS AGREEMENT, NONE OF PURCHASER, SELLER OR ANY OF THEIR RESPECTIVE AFFILIATES SHALL BE ENTITLED TO CONSEQUENTIAL, SPECIAL, INDIRECT, PUNITIVE OR EXEMPLARY DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY AND, EXCEPT AS OTHERWISE PROVIDED IN THIS SENTENCE, EACH OF PURCHASER AND SELLER, FOR ITSELF AND ON BEHALF OF ITS AFFILIATES, HEREBY EXPRESSLY WAIVES ANY RIGHT TO CONSEQUENTIAL, SPECIAL, INDIRECT, PUNITIVE OR EXEMPLARY DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 13.12Recording.  As soon as practicable after Closing, Purchaser shall record the Conveyances and other assignments, if any, delivered at Closing in the appropriate counties as well as with any appropriate governmental agencies and provide Seller with copies of all recorded or approved instruments.

Section 13.13Conspicuous.  SELLER AND PURCHASER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE OR ENFORCEABLE, THE PROVISIONS IN THIS AGREEMENT IN BOLD-TYPE FONT ARE “CONSPICUOUS” FOR THE PURPOSE OF ANY APPLICABLE LAW.

Section 13.14Time of Essence.  This Agreement contains a number of dates and times by which performance or the exercise of rights is due, and the Parties intend that each and every such date and time be the firm and final date and time, as agreed.  For this reason, each Party hereby waives and relinquishes any right it might otherwise have to challenge its failure to meet any performance or rights election date applicable to it on the basis that its late action constitutes substantial performance, to require the other Party to show prejudice, or on any equitable grounds.  Without limiting the foregoing, time is of the essence in this Agreement.  If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 13.15Delivery of Records.  Seller, at Purchaser’s cost and expense, shall deliver the Records to Purchaser as soon as reasonably practicable after the Closing Date, but in no event later than thirty (30) days following Closing.

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Section 13.16Severability.  The invalidity or unenforceability of any term or provision of this Agreement in any situation or jurisdiction shall not affect the validity or enforceability of the other terms or provisions hereof or the validity or enforceability of the offending term or provision in any other situation or in any other jurisdiction and the remaining terms and provisions shall remain in full force and effect, unless doing so would result in an interpretation of this Agreement which is manifestly unjust.

Section 13.17Specific Performance.  The Parties agree that if any of the provisions of this Agreement were not performed in accordance with their specific terms, irreparable damage would occur, no adequate remedy at Law would exist and damages would be difficult to determine, and the Parties shall be entitled to specific performance of the terms hereof and immediate injunctive relief, without the necessity of proving the inadequacy of money damages as a remedy, in addition to any other remedy available at law or in equity.

[Signature Page Follows]

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IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties on the Execution Date.

SELLER:
SABINE MID-CONTINENT LLC
By: Sabine Oil & Gas LLC, its sole Member
By:	/s/ Michael Hinze
Name:	Michael Hinze
Title:	Senior Vice President Land
PURCHASER:
JONES ENERGY HOLDINGS, LLC
By:	/s/ Mike S. McConnell
Name:	Mike S. McConnell
Title:	President

[Signature Page to Purchase and Sale Agreement]

APPENDIX A

ATTACHED TO AND MADE A PART OF THAT CERTAIN
PURCHASE AND SALE AGREEMENT, DATED AS OF NOVEMBER 22, 2013,
BY AND BETWEEN SELLER AND PURCHASER

DEFINITIONS

“Actual Knowledge” has the meaning set forth in Section 5.1(a).

“Adjusted Purchase Price” has the meaning set forth in Section 3.3.

“AFEs” means authorizations for expenditures issued pursuant to a Contract.

“Affiliate” means, with respect to any Person, any Person that directly or indirectly Controls, is Controlled by or is under common Control with such Person; excluding, in each case, Persons that are directly or indirectly Controlled by an institutional equity sponsor of a Party (other than Affiliates Controlled directly or indirectly by such Party).

“Aggregate Benefit Deductible” has the meaning set forth in Section 4.5(b)(ii).

“Aggregate Benefit Threshold” has the meaning set forth in Section 4.5(b)(ii)

“Aggregate Defect Deductible” has the meaning set forth in Section 4.5(b)(i).

“Aggregate Defect Threshold” has the meaning set forth in Section 4.5(b)(i).

“Agreement” has the meaning set forth in Preamble of this Agreement.

“Allocated Value” has the meaning set forth in Section 3.4.

“Arbitration Decision” has the meaning set forth in Section 4.4(d).

“Asset Taxes” means ad valorem, property, excise, sales, use, severance, production or similar taxes (including any interest, fine, penalty or additions to tax imposed by a Governmental Body in connection with such taxes) based upon acquisition, operation or ownership of the Assets or the production of Hydrocarbons therefrom; but excluding, for the avoidance of doubt, income, business activity, capital gains or franchise taxes.

“Assets” has the meaning set forth in Section 2.2.

“Assumed Purchaser Obligations” has the meaning set forth in Section 11.1(a).

“Business Day” means each calendar day except Saturdays, Sundays, and Federal holidays.

“Casualty Loss” means (i) any loss, damage or destruction of the Assets occurring during the period between the Execution Date and the Closing Date for any reason, including any act of God, fire, explosion, collision, earthquake, windstorm, tornado, flood or other casualty, but

Appendix A-1

excluding any loss, damage or destruction as a result of depreciation, ordinary wear and tear and any change in condition of the Assets for production of Hydrocarbons through normal depletion (which exclusion shall include the watering-out of any Well, collapsed casing or sand infiltration of any Well), or (ii) any loss or damage resulting from any portion of the Assets being taken in condemnation or under right of eminent domain.

“Central Time” means the Central Standard Time zone of the United States of America.

“CERCLA” means the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et_seq., as amended.

“Claim Notice” has the meaning set forth in Section 11.3(b).

“Closing” has the meaning set forth in Section 9.1.

“Closing Date” has the meaning set forth in Section 9.1.

“Closing Payment” has the meaning set forth in Section 9.4(a).

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” means that certain Confidentiality Agreement dated October 10, 2013 between Purchaser and Sabine Parent.

“Contracts” has the meaning set forth in Section 2.2(d).

“Control” means the ability to direct the management and policies of a Person through ownership of voting shares or other equity rights, pursuant to a written agreement, or otherwise.  The terms “Controls” and “Controlled by” and other derivatives shall be construed accordingly.

“Conveyance” means the Conveyance attached hereto as Exhibit B.

“COPAS” has the meaning set forth in Section 2.5(a).

“Cure Period” has the meaning set forth in Section 4.2(b).

“Current Tax Period” has the meaning set forth in Section 12.2.

“Customary Post-Closing Consents” means the consents and approvals from Governmental Bodies for the assignment of the Assets to Purchaser that are customarily obtained after the assignment of properties similar to the Assets and in respect of which such Governmental Body is, pursuant to applicable Law, without discretion to refuse to grant such approval or consent if specifically enumerated conditions set forth in such applicable Law are met.

“Cut-off Date” has the meaning set forth in Section 9.4(b).

“Damages” means the amount of any actual liability, loss, cost, expense, claim, award or judgment incurred or suffered by any Person (to be indemnified under this Agreement) arising

Appendix A-2

out of or resulting from the indemnified matter, whether attributable to personal injury or death, property damage, contract claims (including contractual indemnity claims), torts, or otherwise, including reasonable fees and expenses of attorneys, consultants, accountants or other agents and experts reasonably incident to matters indemnified against, and the reasonable costs of investigation and/or monitoring of such matters, and the reasonable costs of enforcement of the indemnity; provided, however, that the term “Damages” shall not include (i) loss of profits or other consequential damages suffered by the Party claiming indemnification, or any punitive damages (except as otherwise provided herein), (ii) any liability, loss, cost, expense, claim, award or judgment to the extent resulting from or to the extent increased by the actions or omissions of any Indemnified Person after the Closing Date and (iii) only in the case of claims under Section 11.2(a)(iii) or Section 11.2(b)(v) (other than in respect of Sections 5.2, 5.3, 5.4, 5.5, 5.6, 5.10, 6.1, 6.2, 6.3, 6.4 and 6.5) any liability, loss, cost, expense, claim, award or judgment that does not individually exceed One Hundred Thousand and No/100 Dollars ($100,000.00).

“Defensible Title” means, with respect to each Well and Undeveloped Property, as applicable, that title of Seller, except for and subject to the Permitted Encumbrances, that:

(i)entitles Seller (and will entitle Purchaser, as successor in interest to Seller) to receive a share of Hydrocarbons produced, saved and marketed from such Well or Undeveloped Property, as applicable, throughout the duration of the productive life of such Well or Undeveloped Property, as applicable (after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests, or other similar burdens on or measured by production of Hydrocarbons) (hereinafter a “Net Revenue Interest”), of not less than the Net Revenue Interest shown Exhibit A-2 for such Well or Undeveloped Property, as applicable; except for (a) decreases in connection with those operations in which Seller has elected in accordance with the terms herein to be a nonconsenting co-owner after the date hereof, (b) decreases resulting from the reversion of interests to co-owners with operations in which such co-owners elect after the date hereof not to consent, (c) decreases resulting from the establishment or amendment after the date hereof of involuntary pools or units, (d) decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under-deliveries and (e) as otherwise shown on Exhibit A-2;

(ii)obligates Seller (and will obligate Purchaser, as successor in interest to Seller) to bear a percentage of the costs and expenses relating to the maintenance, development and operation of such Well or Undeveloped Property, as applicable (hereinafter a “Working Interest”), in an amount not greater than the Working Interest shown in Exhibit A-2 throughout the productive life of such Well or Undeveloped Property, as applicable, except for (a) increases that are accompanied by at least a proportionate increase in Seller’s Net Revenue Interest, (b) increases resulting from contribution requirements with respect to defaults by co-owners under the applicable operating agreement and (c) as otherwise shown on Exhibit A-2; and

(iii)is free and clear of liens, encumbrances, obligations, or defects, other than Permitted Encumbrances.

“Deposit” has the meaning set forth in Section 3.1.

Appendix A-3

“Disputed Title Matters” has the meaning set forth in Section 4.4.

“Disputing Party” has the meaning set forth in Section 4.4.

“Dollars” means U.S. Dollars.

“Effective Time” has the meaning set forth in Section 2.4(a).

“Electing Party” has the meaning set forth in Section 12.5.

“Environmental Defect” means (i) any written notice from a Governmental Body or Third Party asserting or alleging a violation of an Environmental Law or a violation of environmental provisions of a contract or agreement attributable to the use, ownership or operation of the Assets, (ii) a condition on or affecting an Asset which violates an Environmental Law, (iii) a condition on or affecting an Asset with respect to which remedial or corrective action is required under Environmental Law and (iv) any other Environmental Liability.

“Environmental Laws” means, as the same have been amended to the Execution Date, CERCLA, the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et_seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et_seq.; the Clean Air Act, 42 U.S.C. § 7401 et_seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et_seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et_seq.; the Endangered Species Act, 16 U.S.C. §§ 1531 to 1544; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et_seq.; and the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; and all similar Laws as of the Execution Date of any Governmental Body having jurisdiction over the property in question addressing pollution or protection of the environment, human health, natural resources or threatened, endangered or protected species, and all regulations implementing the foregoing that are applicable to the operation and maintenance of the Assets.

“Environmental Liabilities” means any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees and other liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body or court of competent jurisdiction to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources, remediation or response costs to the extent arising out of any violation of, or any remediation obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets.

“Equipment” has the meaning set forth in Section 2.2(f).

“Escrow Account” has the meaning set forth in Section 4.2(d).

“Escrow Agent” means JPMorgan Chase Bank, N.A.

Appendix A-4

“Escrow Agreement” has the meaning set forth in Section 4.2(d).

“Escrow Amount” means the aggregate amount of deposits made in the Escrow Account pursuant to Section 4.2.

“Excluded Assets” means (i) the amounts to which Seller is entitled pursuant to Section 3.3(a), Section 4.2(c), Section 4.2(d) and Section 4.2(f), as applicable, (ii) the Excluded Records, (iii) the Reassigned Properties, (iv) all claims, rights and causes of action of Seller or any of its Affiliates arising under or with respect to any Contract that are attributable to the period of time prior to the Effective Time (including claims for adjustments or refunds) or for which Seller is otherwise required to provide indemnification to Purchaser hereunder, (v) all rights and interests of Seller or its Affiliates (a) under any policy or agreement of insurance or indemnity agreement, (b) under any bond and (c) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omission or events, or damage to or destruction of property prior to the Effective Time or matters for which Seller is otherwise required to provide indemnification to Purchaser hereunder, (vi) all right, title and interest in any oil, gas and interest in oil, gas or mineral leases, overriding royalties, production payments, net profits interests, fee mineral interests, fee royalty interests and other interest in oil, gas, and other minerals set forth on Exhibit A-4, if any, (vii) any Leased Assets that are not transferred to Purchaser at Closing, (viii) all claims of Seller for refunds of, rights to receive funds from any Governmental Authority or loss carry forwards with respect to (a) production or any other Taxes attributable to the Assets for any period prior to the Effective Time or to Seller’s businesses generally (b) income or franchise Taxes of Seller, or (c) any Taxes attributable to the Excluded Assets, (ix) all personal property of Seller (including vehicles, office leases, furniture, office equipment and related peripheral equipment and computers, in each case, irrespective of whether leased or owned) not included within the definition of Assets, (x) all geophysical and other seismic and related technical data and information relating to the Assets (other than the items specifically described in clause (ii) of the definition of “Records”), (xi) all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property, (xii) all data and Contracts that cannot be disclosed to Purchaser as a result of confidentiality arrangements under agreements with Third Parties (provided that Seller uses its commercially reasonable efforts to obtain a waiver of any such confidentiality restriction), (xiii) any of the Assets excluded from the transactions contemplated hereunder pursuant to Section 4.2(c), Section 4.2(d), Section 4.2(f), Section 4.2(h), Section 4.6 or Section 4.7, (xiv) the Giant Gathering Assets, (xv) any right, title or interest acquired by Seller or its Affiliates after the Execution Date (as well as any obligations or rights of Seller or its Affiliates to acquire any such right, title or interest) in and to lands (including any interests in wells, leaseholds and mineral estates thereon or therein, as applicable) covered by any Property (without prejudice, for the avoidance of doubt, to either Party’s rights hereunder in connection with the acquisition of any such right, title or interest in connection with Seller’s cure of a Title Defect pursuant to Section 4.2), and (xvi) any other items expressly excluded under this Agreement or set forth on Exhibit A-4.

“Excluded Defect” has the meaning set forth in the definition of “Title Defect” in this Appendix A; and, for purposes of the last sentence in Section 4.1, will be deemed to include any types of defects described as “Excluded Defects” in such definition that affect the Wells, Leases or the Units.

Appendix A-5

“Excluded Records” means (i) all corporate, financial and Tax data and records of Seller insofar as they relate to Seller’s business generally and are not required to for the future ownership or operation of the Assets, (ii) any records to the extent transfer to Purchaser requires the consent of, or a payment to, a Third Party; provided that Seller shall use commercially reasonable efforts to obtain such consent, (iii) computer software, (iv) all legal records and legal files of Seller insofar as protected by attorney-client privilege between Seller and its legal counsel (other than (a) title opinions, (b) Contracts, (c) records and files with respect to any previous litigation matters (other than litigation matters for which Seller is required to provide indemnification to Purchaser under Section 11.2(b)), (d) Leases and (e) instruments creating easements included as part of the Assets), (v) personnel records, (vi) records relating to the sale of the Assets, including bids received from and records of negotiations with Third Parties and (vii) any records with respect to the Excluded Assets.

“Execution Date” has the meaning set forth in Preamble of this Agreement.

“Failed Cure Amount” has the meaning set forth in Section 4.2(f)(ii).

“Final Disputed Title Matters” has the meaning set forth in Section 4.4(a).

“GAAP” means U.S. generally accepted accounting principles.

“Gas Gathering Agreements” means (i) the Gas Gathering Agreement, dated as of February 1, 2012, Contract No. AH-0001, by and between Le Norman Operating LLC and GGG, as amended by the Amendatory Agreement, dated as of December 3, 2012, by and between Le Norman Operating LLC and GGG, as further amended by the Second Amendatory Agreement, dated as of June 24, 2013, by and between Seller and GGG and (ii) the Gas Gathering Agreement, dated as of March 1, 2012, Contract No. SEC-0001, by and between Le Norman Operating LLC and GGG, as amended by the Amendatory Agreement, dated as of November 30, 2012, by and between Le Norman Operating LLC and GGG, as further amended by the Second Amendatory Agreement, dated as of June 24, 2013, by and between Seller and GGG.

“GGG” means Giant Gas Gathering LLC.

“Giant Gathering Assets” means all (i) equipment, machinery, tools, fixtures, pipelines, flowlines, gathering lines, tangible personal property and improvements, (ii) surface fee interests, easements, permits, licenses, servitudes, rights-of-way, surface leases and other surfaces rights appurtenant to, and used or held for use in connection with, the items described in clause (i), and (iii) contracts, agreements and instruments relating to the items described in clauses (i)and (ii) (limited, however, for purposes of the “Excluded Assets” definition, to GGG’s rights, duties and obligations as the gatherer under the Gas Gathering Agreements), in each case, owned or otherwise held by GGG.

“Governmental Body” means any instrumentality, subdivision, court, administrative agency, commission, official or other authority of the United States or any other country or any state, province, prefect, municipality, locality or other government or political subdivision thereof, or any quasi-governmental or private body exercising any administrative, executive, judicial, legislative, police, regulatory, taxing, importing or other governmental or quasi-governmental authority.

Appendix A-6

“Hazardous Substances” means any pollutants, contaminants, toxic, radioactive or hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of liability under any Environmental Laws, including asbestos-containing materials (but excluding any Hydrocarbons or NORM).

“Hedges Termination Payment” has the meaning set forth in Section 10.4.

“Hydrocarbons” means oil, gas, condensate and other gaseous and liquid hydrocarbons or any combination thereof.

“Imbalances” means any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocated to the interests of Seller therein and the shares of production from the relevant Well to which Seller was entitled, or at the pipeline flange between the amount of Hydrocarbons nominated by or allocated to Seller and the Hydrocarbons actually delivered on behalf of Seller at that point.

“Indemnified Person” has the meaning set forth in Section 11.3(a).

“Indemnifying Person” has the meaning set forth in Section 11.3(a).

“Individual Benefit Threshold” has the meaning set forth in Section 4.5(b)(ii).

“Individual Defect Threshold” has the meaning set forth in Section 4.5(b)(i).

“Laws” means all Permits, statutes, rules, regulations, ordinances, orders, and codes of Governmental Bodies.

“Leased Assets” means all equipment, machinery, tools, fixtures, inventory, field equipment and related assets that are subject to or currently leased by Seller, and used or held for use solely in connection with the operation of, or the production of Hydrocarbons from, the Properties.

“Leases” has the meaning set forth in Section 2.2(a).

“Letter-in-lieu of Transfer Order” means that certain Letter-in-lieu of Transfer Order attached hereto as Exhibit D.

“Net Revenue Interest” has the meaning set forth in the definition of the term “Defensible Title” in this Appendix A.

“Non-electing Party” has the meaning set forth in Section 12.5.

“NORM” means naturally occurring radioactive material.

“Party” and “Parties” have the meanings set forth in the Preamble of this Agreement.

“Permits” means any permits, licenses, approvals, certificates of authority, franchises, concessions, registrations, consents, or similar qualifications or authorizations issued, granted or given by or under the authority of, or filings with, any Governmental Bodies.

Appendix A-7

“Permitted Encumbrances” means any or all of the following:

(i)royalties and any overriding royalties, net profits interests, free gas arrangements, production payments, reversionary interests and other similar burdens on production to the extent that they do not, individually or in the aggregate, reduce Seller’s (or Purchaser’s, as successor in interest to Seller) Net Revenue Interest below that shown in Exhibit A-2 or increase Seller’s (or Purchaser’s, as successor in interest to Seller) Working Interest above that shown in Exhibit A-2 without a corresponding and proportionate increase in the Net Revenue Interest;

(ii)all unit agreements, pooling agreements, operating agreements, farmout agreements, Hydrocarbon production sales contracts and division orders, as well as other contracts, agreements and instruments listed on Schedule 5.12, in each case, to the extent that they do not, individually or in the aggregate, (A) reduce Seller’s (or Purchaser’s, as successor in interest to Seller) Net Revenue Interest below that shown in Exhibit A-2 or increase Seller’s (or Purchaser’s, as successor in interest to Seller) Working Interest above that shown in Exhibit A-2 without a corresponding and proportionate increase in the Net Revenue Interest or (B) detract from the value of, or interfere with the use, development or ownership of any Asset;

(iii)preferential rights to purchase, third-Person consent requirements and similar restrictions (A) that are not applicable to the sale of the Assets contemplated by this Agreement, (B) if unconditional waivers or consents acceptable to Purchaser are obtained from the appropriate Persons prior to the Closing Date, (C) to the extent relating to Excluded Records or other Excluded Assets or (D) for which notices were delivered to the holders thereof or other appropriate Third Parties and in respect of which Seller otherwise fully complied with Section 4.6;

(iv)maintenance of uniform interest provisions contained in an operating agreement if waived by the party or parties having the right to enforce such provision;

(v)liens for Taxes or assessments not yet delinquent or, if delinquent, being contested in good faith by appropriate actions and for which adequate cash reserves are maintained for the payment thereof in accordance with the applicable Contracts;

(vi)materialmen’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s and other similar liens or charges arising in the ordinary course of business for amounts not yet delinquent (including any amounts being withheld as provided by Law) or, if delinquent, being contested in good faith by appropriate actions and for which adequate cash reserves are maintained for the payment thereof in accordance with the applicable Contracts;

(vii)all rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or rights or interests therein if they are not required prior to, or are customarily obtained in the region where the Assets are located subsequent to, the sale or conveyance, including Customary Post-Closing Consents, if such Governmental Body is, pursuant to applicable Law, without discretion to refuse to grant such consent if specifically enumerated conditions set forth in such applicable Law are satisfied;

Appendix A-8

(viii)excepting circumstances where such rights have already been triggered, rights of reassignment arising upon final intention to abandon or release the Assets, or any of them;

(ix)easements, rights-of-way, covenants, servitudes, permits, surface leases and other rights in respect of surface operations which do not, individually or in the aggregate,  prevent or adversely affect the use, ownership, development or operations of any Asset;

(x)calls on production under existing Contracts at market pricing;

(xi)gas balancing and other production balancing obligations, and obligations to balance or furnish make-up Hydrocarbons under Hydrocarbon sales, gathering, processing or transportation contracts, to the extent (i) Purchaser receives a downward adjustment to the Purchase Price in respect of such obligations or (ii) any such obligation arising under a Contract that is listed on Schedule 5.12;

(xii)all rights reserved to or vested in any Governmental Bodies to control or regulate any of the Assets in any manner or to assess Tax with respect to the Assets, the ownership, use or operation thereof, or revenue, income or capital gains with respect thereto, and all obligations and duties under all applicable Laws of any such Governmental Body or under any franchise, grant, license or permit issued by any Governmental Body;

(xiii)any lien, charge or other encumbrance on or affecting the Assets which is expressly waived, bonded or paid by Purchaser at or prior to Closing or which is discharged by Seller at or prior to Closing;

(xiv)any lien or trust arising in connection with workers’ compensation, unemployment insurance, pension or employment Laws or regulations;

(xv)the terms and conditions of the Leases, including any depth limitations or similar limitations that may be set forth therein; and

(xvi)any other liens, charges, encumbrances, defects or irregularities which (a) do not, individually or in the aggregate, detract from the value of or interfere with the use or ownership of the Assets subject thereto or affected thereby, (b) would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties in the region where the Assets are located and (c) do not reduce Seller’s (or Purchaser’s, as successor in interest to Seller) Net Revenue Interest below that shown in Exhibit A-2 or increase Seller’s (or Purchaser’s, as successor in interest to Seller) Working Interest above that shown in Exhibit A-2 without a corresponding and proportionate increase in the Net Revenue Interest of Seller.

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Government Body or any other entity.

“Phase I Environmental Site Assessment” means an environmental site assessment

Appendix A-9

performed pursuant to the American Society for Testing and Materials E1527 - 05, or any similar environmental assessment.

“Phase II Request” has the meaning set forth in Section 7.1(b).

“Post-Effective Time Tax Advances” has the meaning set forth in Section 12.3.

“Prime Rate” means the rate of interest published from time to time as the “Prime Rate” in the “Money Rates” section of The Wall Street Journal.

“Properties” has the meaning set forth in Section 2.2(c).

“Property Costs” means (i) all operating and production expenses (including costs of insurance, rentals, shut-in payments and royalty payments; title examination and curative actions; Asset Taxes; and gathering, processing and transportation costs in respect of Hydrocarbons produced from the Properties) and capital expenditures (including bonuses, broker fees, and other lease acquisition costs, costs of drilling and completing wells and costs of acquiring equipment) incurred and paid in the ownership and operation of the Assets in the ordinary course of business, (ii) general and administrative costs with respect to the Assets and (iii) overhead costs charged to the Assets under the applicable operating agreement.

“Purchaser Hedges” has the meaning set forth in Section 10.4.

“Purchase Price” has the meaning set forth in Section 3.1.

“Purchase Price Allocation Schedule” has the meaning set forth in Section 3.2.

“Purchaser” has the meaning set forth in the Preamble of this Agreement.

“Purchaser Group” means Purchaser, its current and former Affiliates, and each of their respective officers, directors, employees, agents, advisors and other Representatives.

“Purchaser Parent Company” means Jones Energy, Inc.

“Purchaser Parent Guaranty” means the Parent Guaranty attached hereto as Exhibit C.

“Reassigned Properties” means those certain of the Assets reconveyed/reassigned, if any, from Purchaser to Seller pursuant to Section 4.2; provided that any such reconveyancing/reassignment will be effected through the use of a conveyance substantially similar to the Conveyance and will include a special warranty of title, subject to the Permitted Encumbrances, by, through and under Purchaser.

“Records” means copies of any files, records, maps, information, and data, whether written or electronically stored, relating primarily to the Assets, in each case, in the possession of Seller or Sabine Parent, including, without limitation: (i) land and title records (including abstracts of title, title opinions and memoranda, title curative documents and prospect files); (ii) contracts, electric logs, core data, pressure data, decline curves, graphical production curves, and a non-exclusive license to all geophysical data owned by Seller; (iii) correspondence; (iv)

Appendix A-10

operations, production, accounting, lease and division order records; (v) production, facility and well records and data; and (vi) any other records, books and files relating to any of the matters set forth in Section 2.2; provided, however, that the term “Records” shall not include any of the foregoing items that are Excluded Assets.

“Representatives” means (i) partners, employees, officers, directors, members, equity owners and counsel of a Party or any of its Affiliates or any prospective purchaser of a Party or an interest in a Party; (ii) any consultant or agent retained by a Party or the parties listed in subsection (i)above; and (iii) any bank, other financial institution or entity funding, or proposing to fund, such Party’s operations in connection with the Assets, including any consultant retained by such bank, other financial institution or entity.

“Resolved Defect Amount” has the meaning Section 4.2(f)(iii).

“Retained Seller Obligations” has the meaning set forth in Section 11.1(b).

“Sabine Parent” means Sabine Oil & Gas LLC.

“SEC” has the meaning set forth in Section 7.13.

“SEC Documents” has the meaning set forth in Section 7.13.

“SEC Waiver” has the meaning set forth in Section 8.2(g).

“Seller” has the meaning set forth in the Preamble of this Agreement.

“Seller Closing Failure” has the meaning set forth in Section 10.4.

“Seller Group” means Seller, its current and former Affiliates, and each of their respective officers, directors, employees, agents, advisors and other Representatives.

“Seller Parent Guaranty” means the Parent Guaranty attached hereto as Exhibit E.

“Suspense Funds” means proceeds of production and associated penalties and interest in respect of any of the Assets that are payable to third parties and are held in suspense by Sabine Parent as the operator of such Assets.

“Tank Bottom Hydrocarbons” means a mixture of Hydrocarbons, water and other substances that is concentrated at the bottom of storage tanks included in the Assets that is not merchantable (commonly referred to as basic sediment and water or “BS&W”).

“Tax Deferred Exchange” has the meaning set forth in Section 12.5.

“Tax Return” means any return (including any information return), report, statement, schedule, notice, form, election, estimated Tax filing, claim for refund or other document (including any attachments thereto and amendments thereof) filed with or submitted to, or required to be filed with or submitted to, any Governmental Body with respect to any Tax.

“Taxes” means all federal, state, local, and foreign income, profits, franchise, sales, use,

Appendix A-11

ad valorem, property, severance, production, excise, stamp, documentary, real property transfer or gain, gross receipts, goods and services, registration, capital, transfer, or withholding taxes or other assessments, duties, fees or charges imposed by any Governmental Body, including any interest, penalties or additional amounts which may be imposed with respect thereto.

“Third Party” means any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

“Third Party Claim” has the meaning set forth in Section 11.3(b).

“Title Arbitration Notice” has the meaning set forth in Section 4.4(a).

“Title Arbitrator” has the meaning set forth in Section 4.4(b).

“Title Benefit” means any right, circumstance or condition that operates to increase the Net Revenue Interest of Seller as of the Closing Date in any of the Wells or the Undeveloped Properties, as applicable, above that shown on Exhibit A-2 without a greater than proportionate increase in Seller’s Working Interest above that shown in Exhibit A-2.

“Title Benefit Amount” has the meaning set forth in Section 4.3(b).

“Title Benefit Notice” has the meaning set forth in Section 4.3(a).

“Title Benefit Property” has the meaning set forth in Section 4.3(a).

“Title Claim Date” has the meaning set forth in Section 4.2(a).

“Title Defect” means (i) an Environmental Defect or (ii) any lien, charge, encumbrance, obligation, defect, or other similar matter that, if not cured, causes Seller not to have Defensible Title in and to the Wells and the Undeveloped Properties, as applicable, as of the Closing Date; provided, however, that the following shall not be considered Title Defects for any purpose of this Agreement (each an “Excluded Defect”):

(a)defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Purchaser provides affirmative evidence that such failure or omission could reasonably be expected to result in another Person’s superior claim of title to the relevant Asset;

(b)defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(c)defects based on a gap in Seller’s chain of title in the state’s records as to state leases, or in the county records as to other leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in a Title Defect Notice;

(d)defects based on references to lack of information, including lack of information in Seller’s files, the lack of Third Party records, and or the unavailability of

Appendix A-12

information from regulatory agencies;

(e)defects based on references to a document because such document is not in Seller’s files;

(f)defects based on Tax assessment, Tax payment or similar records (or the absence of such activities or records);

(g)defects that have been cured by applicable Laws of limitations or prescription; and

(h)defects Purchaser has waived in writing or may be deemed to have waived pursuant to the provisions of Section 4.2(a).

“Title Defect Amount” has the meaning set forth in Section 4.2(g).

“Title Defect Notice” has the meaning set forth in Section 4.2(a).

“Title Defect Property” has the meaning set forth in Section 4.2(a).

“Unadjusted Purchase Price” has the meaning set forth in Section 3.1.

“Undeveloped Properties” means those Properties set forth on Exhibit A-2 that are not Wells, which such Properties are set forth on Exhibit A-2 on a planned well/unit-by-planned well/unit basis, and shall be limited, for purposes of Section 4.2, in each case, to the portion of such Properties that is included in such planned well/unit (as indicated on Exhibit A-2).

“Unescrowed Amount” has the meaning set forth in Section 4.2(e).

“Units” has the meaning set forth in Section 2.2(b).

“Wells” has the meaning set forth in Section 2.2(c).

“Working Interest” has the meaning set forth in the definition of the term “Defensible Title” in this Appendix A.

Appendix A-13

EX-10.19

Exhibit 10.19

BORROWING BASE INCREASE AGREEMENT

This BORROWING BASE INCREASE AGREEMENT (this “Agreement”) dated as of December 18, 2013 (the “Effective Date”), is among Jones Energy Holdings, LLC, a Delaware limited liability company (the “Borrower”), the undersigned subsidiaries of the Borrower as guarantors (the “Guarantors”), the Lenders (as defined below) and Wells Fargo Bank, N.A. (“Wells Fargo”), in its capacity as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

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 parties hereto wish to increase the Borrowing Base (as defined in the Credit Agreement) as set forth 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 and used herein without definition shall have the meaning assigned to such term in the Credit Agreement.

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.Increase in the Borrowing Base.  Subject to the terms of this Agreement, as of the Effective Date, the Borrowing Base shall be increased from $500,000,000 to $575,000,000 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.  The parties hereto acknowledge and agree that the Borrowing Base redetermination set forth in this Section 3 shall be deemed to be the Scheduled Redetermination scheduled for August 1, 2013 as provided in Section 2.07 of the Credit Agreement.  Each Lender’s Applicable

Percentage of the resulting Borrowing Base, after giving effect to the increase in the Borrowing Base set forth in this Section 3, is set forth in Annex A attached hereto.

Section 4.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 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 5.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 shall have received:

(i)multiple original counterparts, as requested by the Administrative Agent, of this Agreement duly and validly executed and delivered by duly authorized officers of the Borrower, the Guarantors, the Administrative Agent, and the Lenders;

(ii)a certificate, dated as of the Effective Date, duly executed and delivered by the Borrower’s and each Guarantor’s authorized officer as to (A) no change in the officers’ incumbency delivered in connection with the closing of Waiver, Agreement and Amendment No. 7 to Credit Agreement and Amendment to Guarantee and Collateral Agreement dated as of June 12, 2013 (“Amendment No. 7”), among the Credit Parties, the Administrative Agent and certain of the Lenders, which amended the Credit Agreement, (B) no change in authorizing resolutions delivered in connection with the closing of Amendment No. 7, and (C) no change in organizational documents delivered in connection with the closing of Amendment No. 7 or, if any such changes have occurred, attaching new incumbency certificates, authorizing resolutions and/or organizational documents, as they case may be; and

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(iii)executed and notarized new mortgages or deeds of trust or supplements to existing mortgages or deeds of trust covering additional Oil and Gas Properties of the Borrower and its Subsidiaries, in form and substance reasonably satisfactory to the Administrative Agent, to the extent necessary to cause the Administrative Agent to have a first priority, perfected Lien (subject only to Liens permitted under 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 Reports most recently delivered to the Administrative Agent.

(b)The representations and warranties in this Agreement shall be true and correct in all material respects.

(c)The Borrower shall have paid the fee required under Section 6(e) below.

Section 6.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.  This Agreement shall not constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Loan Documents, (ii) any of the agreements, terms or conditions contained in any of the Loan Documents, (iii) any rights or remedies of the Administrative Agent, the Issuing Bank, or any Lender with respect to the Loan Documents, 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.

(c)The Borrower, each Guarantor, the Administrative Agent, the Issuing Bank and each Lender do hereby adopt, ratify, and confirm the Credit Agreement and acknowledge and agree that the Credit Agreement 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, the Guarantee and Collateral Agreement, and the other Loan Documents are not impaired in any respect by this Agreement.

(d)This Agreement is a Loan Document for the purposes of the provisions of the other Loan Documents.

(e)The Borrower hereby agrees to pay a Borrowing Base increase fee for the ratable account of the Lenders equal to 0.40% of the increase in the Borrowing Base effected under Section 3 above.  Such increase fee is (i) due and payable on the Effective Date, (ii) deemed fully earned upon becoming due and payable, (iii) not refundable upon payment thereof, and (iv) in addition to, and not in lieu of, any other fees as the Borrower may have agreed to pay under the Loan Documents.

Section 7.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

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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 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 8.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 9.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 10.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 11.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 12.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]

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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/ Michael McConnell
		Michael McConnell
		President
GUARANTORS:	JONES ENERGY, LLC
	NOSLEY ASSETS, LLC
	Each by:		/s/ Michael McConnell
			Michael McConnell
			President

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

ADMINISTRATIVE AGENT/
LENDER:
	WELLS FARGO BANK, N.A.,
	as the Administrative Agent, a Lender and an Assignor
	By:	/s/ Paul Squires
		Paul Squires
		Managing Director

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	CAPITAL ONE, NATIONAL ASSOCIATION
	By:	/s/ Nancy Mak
	Name:	Nancy Mak
	Title:	Senior Vice President

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	UNION BANK, N.A.
	By:	/s/ Haylee Dallas
	Name:	Haylee Dallas
	Title:	Vice President

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	CREDIT AGRICOLE CORPORATE AND
	INVESTMENT BANK
	By:	/s/ Michael D. Willis
	Name:	Michael D. Willis
	Title:	Managing Director
	By:	/s/ Dennis E. Petito
	Name:	Dennis E. Petito
	Title:	Managing Director

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	JPMORGAN CHASE BANK, N.A.
	By:	/s/ Ryan Aman
	Name:	Ryan Aman
	Title:	Authorized Officer

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	TORONTO DOMINION (NEW YORK) LLC
	By:	/s/ Debbi L. Brito
	Name:	Debbi L. Brito
	Title:	Authorized Signatory

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	COMERICA BANK
	By:	/s/ William Robinson
	Name:	William Robinson
	Title:	Vice President

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

LENDER:	SUNTRUST BANK
	By:	/s/ Shannon Juhan
	Name:	Shannon Juhan
	Title:	Vice President

Signature Page to

Borrowing Base Increase Agreement

(Jones Energy Holdings, LLC)

ANNEX A

BORROWING BASE AS OF DECEMBER 18, 2013*

Name of Lender	Applicable  Percentage		Applicable Percentage of the  Borrowing Base
Wells Fargo Bank, N.A.	19.38776	%	$	111,479,591.84
Union Bank, N.A.	13.26531	%	$	76,275,510.20
Credit Agricole Corporate and Investment Bank	13.26531	%	$	76,275,510.20
Capital One, National Association	13.26531	%	$	76,275,510.20
JPMorgan Chase Bank, N.A.	13.26531	%	$	76,275,510.20
Toronto Dominion (New York) LLC	9.18367	%	$	52,806,122.45
Comerica Bank	9.18367	%	$	52,806,122.45
SunTrust Bank	9.18367	%	$	52,806,122.45
TOTAL	100.000000000	%	$	575,000,000.00

*Borrowing Base is subject to redetermination pursuant to the terms of the Credit Agreement, as amended.

Annex A

EX-10.20

Exhibit 10.20

AGREEMENT AND AMENDMENT NO. 8 TO CREDIT AGREEMENT

This AGREEMENT AND AMENDMENT NO. 8 TO CREDIT AGREEMENT (this “Agreement”) dated as of January 29, 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) and Wells Fargo Bank, N.A. (“Wells Fargo”), in its capacity as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

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.Contemporaneous with the execution of this Agreement, Jones Parent will become a Guarantor (as defined in the Credit Agreement, as amended hereby).

C.The Borrower has requested that the Lenders agree to amend certain provisions of the Credit Agreement as set forth 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.Amendments to Credit Agreement.

(a)The Table of Contents, Articles I, II, IV, and V through XII of the Credit Agreement are hereby amended and restated in their entirety as set forth in Annex 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 4.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.

Section 5.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 shall have received multiple original counterparts, as requested by the Administrative Agent, of this Agreement duly and validly executed and delivered by duly authorized officers of the Borrower, the Guarantors, the Administrative Agent, and the Lenders.

(b)The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of Jones Parent setting forth resolutions of its board of directors or other appropriate governing body with respect to the authorization of Jones Parent 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 Jones Parent (y) who are authorized to sign the Loan Documents to which Jones Parent is a party and (z) who will, until replaced by another officer or

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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 Credit Agreement, as amended hereby, and the transactions contemplated hereby and thereby, specimen signatures of such authorized officers, and the Organizational Documents of Jones Parent, certified as being true and complete.  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 Jones Parent in its jurisdiction of incorporation.

(d)The Administrative Agent shall have received from Jones Parent, a duly executed counterpart (in such number as may be requested by the Administrative Agent) of a guarantee and collateral agreement in form and substance satisfactory to the Administrative Agent.

(e)The Administrative Agent shall have received appropriate UCC search reports for the jurisdiction of organization of Jones Parent reflecting no prior Liens (other than Liens permitted by Section 9.19 of the Credit Agreement, as amended hereby) encumbering the Properties of Jones Parent.

(f)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)).

(g)The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of the Borrower setting forth resolutions of its board of directors or other appropriate governing body with respect to the authorization of the Borrower 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 (y) who are authorized to sign the Loan Documents to which the Borrower 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 Credit Agreement, as amended hereby, and the transactions contemplated hereby and thereby, specimen signatures of such authorized officers, and the Organizational Documents of the Borrower, 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.  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.

(h)The representations and warranties in this Agreement shall be true and correct in all material respects.

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Section 6.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.  By executing this Agreement, Jones Parent hereby becomes a party to the Credit Agreement, as amended hereby, with the same force and effect as if originally named therein as a party thereto and, without limiting the generality of the foregoing, Jones Parent hereby expressly agrees to the covenants set forth in Article VIII and Article IX of the Credit Agreement, as amended hereby, which are applicable to Jones Parent and to such other provisions of the Credit Agreement, as amended hereby, which may be applicable to Jones Parent as a party thereto.

(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.

(e)Each Lender hereby requires, and each Credit Party hereby authorizes, Jones Parent to become a Grantor under the guarantee and collateral agreement referred to in Section 5(d) above, which Security Instrument shall provide for a Lien in substantially all assets of Jones Parent consistent with the scope of assets covered by the Guarantee and Collateral Agreement other than an exclusion for the Equity Interests issued by the Borrower (which, for the avoidance of doubt, shall not be subject to such Lien granted thereunder).

Section 7.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

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execution and delivery of this Agreement does not indicate or establish an approval or consent 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 8.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 9.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 10.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 11.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 12.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]

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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

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

ADMINISTRATIVE AGENT/
LENDER:
	WELLS FARGO BANK, N.A.,
	as the Administrative Agent, a Lender and an Assignor
	By:	/s/ Paul Squires
		Paul Squires
		Managing Director

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	CAPITAL ONE, NATIONAL ASSOCIATION
	By:	/s/ Nancy Mak
		Nancy Mak
		Senior Vice President

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	UNION BANK, N.A.
	By:	/s/ Lauren Trussell
		Lauren Trussell
		Vice President

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	CREDIT AGRICOLE CORPORATE AND
	INVESTMENT BANK
	By:	/s/ Michael Willis
		Michael Willis
		Managing Director
	By:	/s/ Dennis Petito
		Dennis Petito
		Managing Director

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	JPMORGAN CHASE BANK, N.A.
	By:	/s/ Ryan Aman
		Ryan Aman
		Authorized Officer

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	TORONTO DOMINION (NEW YORK) LLC
	By:	/s/ Masqood Fikree
		Masqood Fikree
		Authorized Signatory

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	COMERICA BANK
	By:	/s/ William B.Robinson
		William B.Robinson
		Vice President

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:	SUNTRUST BANK
	By:	/s/ Shannon Juhan
		Shannon Juhan
		Vice President

Signature Page to

Agreement and Amendment No. 8 to Credit Agreement

(Jones Energy Holdings, LLC)

ANNEX A

[see attached]

ANNEX A TO AGREEMENT AND AMENDMENT NO. 8 TO CREDIT AGREEMENT

CREDIT AGREEMENT

DATED AS OF

DECEMBER 31, 2009

AMONG

JONES ENERGY HOLDINGS, LLC
AS BORROWER,

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	26
Section 1.04	Terms Generally; Rules of Construction	26
Section 1.05	Accounting Terms and Determinations	26
ARTICLE II
THE CREDITS
Section 2.01	Commitments	27
Section 2.02	Loans and Borrowings	27
Section 2.03	Requests for Borrowings	28
Section 2.04	Interest Elections	29
Section 2.05	Funding of Borrowings	30
Section 2.06	Termination and Reduction of Aggregate Maximum Credit Amounts	31
Section 2.07	Borrowing Base	32
Section 2.08	Letters of Credit	35
ARTICLE III
PAYMENTS OF PRINCIPAL AND INTEREST; PREPAYMENTS; FEES
Section 3.01	Repayment of Loans	40
Section 3.02	Interest	40
Section 3.03	Alternate Rate of Interest	41
Section 3.04	Prepayments	41
Section 3.05	Fees	43
ARTICLE IV
PAYMENTS; PRO RATA TREATMENT; SHARING OF SET-OFFS
Section 4.01	Payments Generally; Pro Rata Treatment; Sharing of Set-offs	44
Section 4.02	Presumption of Payment by the Borrower	45
Section 4.03	Certain Deductions by the Administrative Agent	45
Section 4.04	Disposition of Proceeds	46
ARTICLE V
INCREASED COSTS; BREAK FUNDING PAYMENTS; TAXES; ILLEGALITY
Section 5.01	Increased Costs	46
Section 5.02	Break Funding Payments	47
Section 5.03	Taxes	48
Section 5.04	Mitigation Obligations; Replacement of Lenders	51
Section 5.05	Illegality	52

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ARTICLE VI
CONDITIONS PRECEDENT
Section 6.01	[Intentionally Omitted]	52
Section 6.02	Each Credit Event	53
ARTICLE VII
REPRESENTATIONS AND WARRANTIES
Section 7.01	Organization; Powers	53
Section 7.02	Authority; Enforceability	53
Section 7.03	Approvals; No Conflicts	54
Section 7.04	Financial Condition; No Material Adverse Change	54
Section 7.05	Litigation	55
Section 7.06	Environmental Matters	55
Section 7.07	Compliance with the Laws and Agreements; No Defaults	56
Section 7.08	Investment Company Act	56
Section 7.09	Taxes	56
Section 7.10	ERISA	57
Section 7.11	Disclosure; No Material Misstatements	57
Section 7.12	Insurance	58
Section 7.13	Restriction on Liens	58
Section 7.14	Subsidiaries	58
Section 7.15	Location of Business and Offices	58
Section 7.16	Properties; Titles, Etc	58
Section 7.17	Maintenance of Properties	59
Section 7.18	Gas Imbalances, Prepayments	60
Section 7.19	Marketing of Production	60
Section 7.20	Swap Agreements	60
Section 7.21	Use of Loans and Letters of Credit	60
Section 7.22	Solvency	61
Section 7.23	OFAC; Anti-Terrorism	61
Section 7.24	Farmout Agreements	61
ARTICLE VIII
AFFIRMATIVE COVENANTS
Section 8.01	Financial Statements; Other Information	62
Section 8.02	Notices of Material Events	65
Section 8.03	Existence; Conduct of Business	65
Section 8.04	Payment of Taxes	65
Section 8.05	[Intentionally Omitted]	66
Section 8.06	Operation and Maintenance of Properties; Farmouts	66
Section 8.07	Insurance	66
Section 8.08	Books and Records; Inspection Rights	67
Section 8.09	Compliance with Laws	67
Section 8.10	Environmental Matters	67
Section 8.11	Further Assurances	68

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Section 8.12	Reserve Reports	68
Section 8.13	Title Information	70
Section 8.14	Additional Collateral; Additional Guarantors	71
Section 8.15	ERISA Compliance	72
Section 8.16	Swap Agreements	72
Section 8.17	Marketing Activities	72
Section 8.18	[Intentionally Omitted]	72
Section 8.19	Designation of Senior Debt	72
ARTICLE IX
NEGATIVE COVENANTS
Section 9.01	Financial Covenants	73
Section 9.02	Debt	73
Section 9.03	Liens	74
Section 9.04	Dividends, Distributions and Redemptions	75
Section 9.05	Investments, Loans and Advances	76
Section 9.06	Nature of Business; International Operations	78
Section 9.07	[Intentionally Omitted.]	78
Section 9.08	Proceeds of Loans	78
Section 9.09	ERISA Compliance	78
Section 9.10	Sale or Discount of Receivables	79
Section 9.11	Mergers, Etc.	79
Section 9.12	Sale of Properties	79
Section 9.13	Transactions with Affiliates	80
Section 9.14	Subsidiaries	81
Section 9.15	Negative Pledge Agreements; Dividend Restrictions	81
Section 9.16	Gas Imbalances, Take-or-Pay or Other Prepayments	81
Section 9.17	Swap Agreements	82
Section 9.18	Change in Business; Corporate Structure; Accounting Change	85
Section 9.19	Parent Company	86
ARTICLE X
EVENTS OF DEFAULT; REMEDIES
Section 10.01	Events of Default	87
Section 10.02	Remedies	90
ARTICLE XI
THE ADMINISTRATIVE AGENT
Section 11.01	Appointment; Powers	91
Section 11.02	Duties and Obligations of Administrative Agent	91
Section 11.03	Action by Administrative Agent	92
Section 11.04	Reliance by Administrative Agent	92
Section 11.05	Subagents	93
Section 11.06	Resignation or Removal of Administrative Agent	93

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Section 11.07	Administrative Agent as Lender	93
Section 11.08	No Reliance	94
Section 11.09	Administrative Agent May File Proofs of Claim	94
Section 11.10	Authority of Administrative Agent to Release Collateral and Liens	95
Section 11.11	The Arranger; Other Agents	96
ARTICLE XII
MISCELLANEOUS
Section 12.01	Notices	96
Section 12.02	Waivers; Amendments	97
Section 12.03	Expenses, Indemnity; Damage Waiver	98
Section 12.04	Successors and Assigns	101
Section 12.05	Survival; Revival; Reinstatement	104
Section 12.06	Counterparts; Integration; Effectiveness	105
Section 12.07	Severability	105
Section 12.08	Right of Setoff	105
Section 12.09	GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS	106
Section 12.10	Headings	107
Section 12.11	Confidentiality	107
Section 12.12	Interest Rate Limitation	108
Section 12.13	EXCULPATION PROVISIONS	109
Section 12.14	Collateral Matters; Swap Agreements	109
Section 12.15	No Third Party Beneficiaries	110
Section 12.16	USA Patriot Act Notice	110
Section 12.17	Keepwell	110
Section 12.18	Flood Insurance Regulations	110

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ANNEXES, EXHIBITS AND SCHEDULES

Annex I	List of Maximum Credit Amounts
Exhibit A	Form of 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	Form of Intercreditor Agreement
Exhibit I	Forms of U.S. Tax Compliance Certificates
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

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THIS CREDIT AGREEMENT dated as of December 31, 2009 is among: JONES ENERGY HOLDINGS, LLC, a Delaware limited liability company, as borrower (the “Borrower”); 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 1.01Terms Defined Above.  As used in this Agreement, each term defined above has the meaning indicated above.

Section 1.02Certain 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 9.17(d)(i).

“Actual PDP Volumes” means, as of any date of determination, the monthly average of actual volume of production from the Oil and Gas Properties of the Credit Parties for the three-month period referred to in Section 8.01(n)(ii) as set forth in the most recent Quarter-End Production Report delivered pursuant to Section 8.01(n).

“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.

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“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. 4 Effective Date” means November 2, 2012.

“Amendment No. 8 Effective Date” means January 29, 2014.

“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

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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. 8 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

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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 8.13(c) or Section 9.12(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),

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(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.

“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).

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“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.

“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 to be 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

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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 9.12.

“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

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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, the Second Lien Credit Agreement, any amendments, amendments and restatements or other modifications to this Agreement or the Second Lien Credit 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” 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

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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

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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

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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, with respect to the Administrative Agent, any Lender, the Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of a Credit Party hereunder or under any other Loan Document (each of the foregoing, for purposes of this definition, a “recipient”), (a) Taxes imposed on (or measured by) net income (however denominated) and franchise Taxes, in each case, (i) imposed by the United States of America or such other jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located (or any political subdivision of any of the foregoing) or (ii) that are Other Connection Taxes, (b) any branch profits Taxes imposed by the United States of America or any similar Tax imposed by any other jurisdiction described in clause (a) above, (c) any 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. 8 Effective Date or on the date on which (i) such recipient 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) in the case of a Lender, 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 recipient’s assignor immediately before such recipient became

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a party hereto or to such Lender immediately before it changed its lending office, (d) Taxes attributable to such recipient’s failure to comply with Section 5.03(e) or Section 5.03(f), and (e) any U.S. federal withholding Taxes imposed under FATCA.

“FATCA” means Sections 1471 through 1474 of the Code, as of the Amendment No. 8 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.

“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.

“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.

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“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.

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“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.

“Intercreditor Agreement” means that certain Intercreditor Agreement among the Administrative Agent, Wells Fargo Energy Capital, Inc. as the administrative agent under the Second Lien Term Loan Agreement, and the Borrower substantially in the form attached hereto as Exhibit H, as the same may from time to time be amended, modified, supplemented or restated as permitted therein.

“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).

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“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” means Jones Energy, Inc., a Delaware corporation.

“LC Commitment” at any time means Twenty Five Million dollars ($25,000,000).

“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

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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.  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 Eighth Amendment Effective Date.

“Loan Documents” means this Agreement, the Notes, the Letter of Credit Agreements, the Letters of Credit, the Security Instruments and the Intercreditor Agreement.

“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

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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 (a) 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 and (b)  Debt under the Second Lien Term Loan Documents.  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 5, 2017.

“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 (a) 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 (b) modified from time to time pursuant to any assignment permitted by Section 12.04(b).

“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.

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“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 the Administrative Agent, any Lender, the Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of a Credit Party under any Loan Document (each of the foregoing, a “recipient” for purposes of this definition), 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).

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“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).

“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 9.19 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(i); (e) such new Debt is not incurred or guaranteed by a non-Guarantor if

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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 members or partners 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 its members or partners 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 member or partner 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 PDP Volumes” means the anticipated projected production from proved, developed, producing Oil and Gas Properties set forth in the most recently delivered Reserve Report (after giving effect to (1) any pro forma adjustments for the consummation of any acquisitions or dispositions of Oil and Gas Properties since the effective date of such Reserve Report and (2) any adjustments for changes in the anticipated projected production from proved, developed, producing Oil and Gas Properties since the effective date of such Reserve Report based on the actual production of Hydrocarbons and set forth in the most recent monthly production report delivered to the Administrative Agent pursuant to Section 8.01(n)).

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“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(n) with respect to each calendar month that is the last month of a fiscal quarter.

“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.

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“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 8.10(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 July 1st (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 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.

“Sanctioned Entity” means (a) a country or a government of a country, (b) an agency of the government of a country, (c) an organization directly or indirectly controlled by a country or its government, (d) a Person resident in a country, in each case, that is subject to a country sanctions program administered and enforced by OFAC.

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“Sanctioned Person” means a person named on the list of Specially Designated Nationals maintained by OFAC.

“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.

“Second Lien Notes” means the Debt arising under the Second Lien Term Loan Agreement regardless of whether such Debt is evidenced by promissory notes, as such Debt may be amended, modified, replaced, extended and rearranged as permitted by Section 9.04(b).

“Second Lien Term Loan Agreement” means that certain Second Lien Term Loan Credit Agreement dated as of the date hereof among the Borrower, Wells Fargo Energy Capital, Inc., as the Administrative Agent thereunder, and the lenders party thereto, together with all amendments, modifications and supplements thereto permitted by Section 9.04(b).

“Second Lien Term Loan Documents” means the Second Lien Term Loan Agreement, the Second Lien Notes and any “Loan Documents” (as defined therein), in each case, together with all amendments, modifications and supplements thereto permitted by Section 9.04(b).

“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(i).

“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

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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 8.14(b).

“Subject Acquisition” has the meaning assigned such term in Section 9.17(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”.

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“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 9.17(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 ending on or after December 31, 2013, 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.

“Triggering Event” means (a) any Swap Event or (b) any Oil and Gas Disposition.

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“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.

“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.

Section 1.03Types 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 1.04Terms 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”.  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 1.05Accounting 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

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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 2.01Commitments.  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 2.02Loans 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

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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 2.03Requests 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;

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(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 2.04Interest 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.

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(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 2.05Funding 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 

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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 2.06Termination 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

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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 2.07Borrowing Base.

(a)Initial Borrowing Base.  For the period from and including the Amendment No. 8 Effective Date to but excluding the first Redetermination Date thereafter, the amount of the Borrowing Base shall be $575,000,000.  Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to Section 8.13(c) or Section 9.12(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 February 1 and August 1 of each year, commencing February 1, 2014. 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 8.12(a) and (c), and, in the case of an Interim Redetermination, pursuant to Section 8.12(b) and (c) and (B) such other reports, data and supplemental information, including, without limitation, the information provided pursuant to Section 8.12(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

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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 8.12(a) and (c) in a timely and complete manner, then on or before the January 15th and July 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 8.12(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

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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 8.12(a) and (c) in a timely and complete manner, then on the May 1st or November 1st, 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 8.12(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 8.13(c) or Section 9.12(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 that results in the aggregate principal amount of all Senior Unsecured Debt Incurrence since the Effective Date exceeding $400,000,000 (such amount in excess of $400,000,000 being referred to herein as the “Excess Amount”), the Borrowing Base then in effect shall be automatically reduced on the date of such incurrence by an amount equal to 25% of the Excess Amount; and

(ii)With respect to any Triggering Event, if, after giving effect thereto, the sum of (x) 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) and (y) the aggregate Swap Event Reduction Amount 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 Triggering Event is effected by an amount equal to (A) in the case of an Oil and Gas Disposition, 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 (B) in the case of a Swap Event, the Swap Event Reduction Amount in respect thereof, as reasonably determined by the Required Lenders.

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Section 2.08Letters 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

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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

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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.

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(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), or (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), 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, in the case of an Event of Default, the LC Exposure, and in the case of a payment required by Section 3.04(c), the amount of such excess as provided in Section 3.04(c), 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(i) or Section 10.01(j).  The Borrower hereby grants to the Administrative Agent, for the benefit of the Issuing Bank and the Secured

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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

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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 3.01Repayment 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 3.02Interest.

(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.

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(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 3.03Alternate 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 3.04Prepayments.

(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

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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 8.13(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

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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 3.05Fees.

(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

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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.

(d)Defaulting Lender Fees.  The Borrower shall not be obligated to pay the Administrative Agent any Defaulting Lender’s ratable share of the fees described in Section 3.05(a) and (b) for the period commencing on the day such Defaulting Lender becomes a Defaulting Lender and continuing for so long as such Lender continues to be a Defaulting Lender.

ARTICLE IV
Payments; Pro Rata Treatment; Sharing of Set-offs

Section 4.01Payments 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.

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(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 4.02Presumption 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 4.03Certain 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.  If at any time prior to the acceleration or maturity of the Loans, the Administrative Agent shall receive any payment in

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respect of principal of a Loan or a reimbursement of an LC Disbursement while one or more Defaulting Lenders shall be party to this Agreement, the Administrative Agent shall apply such payment first to the Borrowing(s) for which such Defaulting Lender(s) shall have failed to fund its pro rata share until such time as such Borrowing(s) are paid in full or each Lender (including each Defaulting Lender) is owed its Applicable Percentage of all Loans then outstanding.  After acceleration or maturity of the Loans, all principal will be paid ratably as provided in Section 10.02(c).

Section 4.04Disposition 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

Section 5.01Increased Costs.

(a)Eurodollar Changes in Law.  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) for Eurocurrency liabilities under Regulation D of the Board (as the same may be amended, supplemented or replaced from time to time) or otherwise; or

(ii)impose on any Lender or the London interbank market any other condition (other than with respect to Indemnified Taxes or Excluded Taxes) affecting this Agreement or Eurodollar Loans made (or deemed to be made) by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar 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.

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(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), 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), (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

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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 the Borrower, any Guarantor or the Administrative Agent shall be required by applicable law (as determined in the good faith discretion of the Borrower, Guarantor or Administrative Agent, as applicable) to deduct or withhold any Tax from such payments, then (i) the Borrower, such Guarantor or the Administrative Agent, as applicable, 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 Administrative Agent, Lender or Issuing Bank (as the case may be) 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 the Administrative Agent, each Lender and the Issuing Bank, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes paid by the Administrative Agent, such Lender or the Issuing Bank, as the case may be, 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.  If the Administrative Agent, a Lender or the Issuing Bank, as applicable, determines, in its sole discretion exercised in good faith, that it has received a refund of any Indemnified Taxes as to which it has been indemnified by a Credit Party or with respect to which a Credit Party has paid additional amounts pursuant to this Section 5.03, it shall pay over such refund to the Borrower (but only to the extent of indemnity payments made, or additional amounts paid, by a Credit Party under this Section 5.03 with respect to the Indemnified Taxes giving rise to such refund); provided, that the Borrower, upon the request of the Administrative Agent, such Lender or the

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Issuing Bank, as applicable, agrees to repay the amount paid over to the Borrower pursuant to this sentence (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent, such Lender or the Issuing Bank, as applicable, in the event the Administrative Agent, such Lender or the Issuing Bank (as the case may be) is required to repay such refund to such Governmental Authority.  The immediately preceding sentence shall not be construed to require the Administrative Agent, any Lender or the Issuing Bank to make available its Tax returns (or any other information relating to its taxes that it deems confidential) to the Borrower or any other Person.

(ii)Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 12.04(c)(D) and (ii) 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 (which, for purposes of this Section 5.03(e) and Section 5.03(f), shall include any Issuing Bank and the Administrative Agent) 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.

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(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 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 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

(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, 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;

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(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. 8 Effective Date.

(g)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

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(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.

ARTICLE VI
Conditions Precedent

Section 6.01[Intentionally Omitted].

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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

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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 heretofore 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, 2012, certified by a Financial Officer of the Borrower.  Jones Parent has heretofore 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 September 30, 2013, 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, 2012 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.

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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;

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(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

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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

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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 8.07, 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 9.15, 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(m) and in connection with the joinder of any Subsidiary under the Guarantee and Collateral Agreement pursuant to Section 8.14(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

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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

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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 8.12(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(e), 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.

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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.  Neither the Borrower nor any Subsidiary of the Borrower is in violation of any of the country or list based economic and trade sanctions administered and enforced by OFAC.  Neither the Borrower nor any Subsidiary of the Borrower (a) is a Sanctioned Person or a Sanctioned Entity, (b) has its assets located in Sanctioned Entities, or (c) derives revenues from investments in, or transactions with, Sanctioned Persons or Sanctioned Entities.  No proceeds of any Loan will be used to fund any operations in, finance any investments or activities in, or make any payments to, a Sanctioned Person or a Sanctioned Entity.

Section 7.24Farmout Agreements.

(a)As of the date hereof and as of each date on which the certificate described in Section 8.12(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 8.12(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 8.12(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.

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(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

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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)[Intentionally Omitted].

(e)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.

(f)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 8.07, 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.

(g)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.

(h)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.

(i)Notices Under Material Instruments.  Promptly after the furnishing or receipt thereof, (a) copies of any notices of redemption, defeasance, conversion, retirement or acquisition of, or under, any Disqualified Capital Stock, if any, of the Borrower and (b) copies of any notices of default under the Second Lien Term Loan Documents not otherwise required to be furnished to the Lenders pursuant to any other provision of this Section 8.01.

(j)Lists of Purchasers.  Concurrently with the delivery of any Reserve Report to the Administrative Agent pursuant to Section 8.12, a list of all Persons purchasing Hydrocarbons from the Credit Parties.

(k)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 9.12 and such sale, transfer, assignment, or other disposition would cause an automatic reduction of the Borrowing Base

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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.

(l)Notice of Casualty Events.  Prompt written notice, and in any event within five Business Days, of the occurrence of any Casualty Event.

(m)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.

(n)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 monthly average of actual volume of production from the Oil and Gas Properties of the Credit Parties for 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.

(o)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.

(p)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.

(q)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

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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 9.11; 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 9.11.

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

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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 any Property of the Borrower or any Guarantor.

Section 8.05[Intentionally Omitted].

Section 8.06Operation 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 8.06.

Section 8.07Insurance.  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

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same or similar businesses operating in the same or similar locations (provided, that this Section 8.07 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 8.08Books 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 8.09Compliance 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 8.10Environmental 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

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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 8.11Further 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 8.12Reserve Reports.

(a)On or before January 15 and July 15 of each year, commencing January 15, 2014, 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 July 1, as applicable, of such year.  The Reserve Report to be delivered on or before January 15

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of each year shall be prepared by one or more Approved Petroleum Engineers, and the Reserve Report to be delivered on or before July 15 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 1st 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 1st 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.

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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 8.13Title Information.

(a)Within thirty (30) days of delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 8.12(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.

(b)If the Borrower has provided title information for additional Properties under Section 8.13(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.

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Section 8.14Additional 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 8.12(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 8.12(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 8.14(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.

(c)The Borrower agrees that it will not, and will not permit any Guarantor to, grant a Lien on any Property to secure the Second Lien Notes without contemporaneously granting to the Administrative Agent, as security for the Indebtedness, a first-priority, perfected Lien (subject to Liens permitted by Section 9.03, it being understood that the Liens permitted under Section 9.03(c) shall be subordinated to the Liens securing the Indebtedness pursuant to the terms and conditions of the Intercreditor Agreement) on the same Property pursuant to Security Instruments in form and substance reasonably satisfactory to the Administrative Agent.  In connection therewith, the Borrower shall, and shall cause each Guarantor to, execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

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Section 8.15          ERISA 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 8.16          Swap 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 8.17          Marketing 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 8.18          [Intentionally Omitted].

Section 8.19          Designation 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(i)), 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

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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 9.01          Financial 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 December 31, 2013, 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, (B) current maturities under this Agreement, and (C) current maturities under the Second Lien Term Loan Agreement), as of the last day of each fiscal quarter, commencing with the fiscal quarter ended December 31, 2013, to be less than 1.0 to 1.0.

Section 9.02          Debt.  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)           Debt under the Second Lien Term Loan Documents, the principal amount of which Debt does not exceed the applicable amount set forth in the Intercreditor Agreement;

(f)            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;

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(g)           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;

(h)           Debt of the Borrower or Subsidiary Guarantor consisting of obligations to pay insurance premiums;

(i)            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 $500,000,000, (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 (v) until such time as the obligations under the Second Lien Term Loan Documents are repaid in full, the net proceeds of such Debt are applied to repay the obligations under the Second Lien Term Loan Documents;

(j)            [Intentionally Omitted]; and

(k)           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), (i) or (k) above, such calculation shall not include any guarantee by a Credit Party in respect of other Debt already included in such calculation.

Section 9.03          Liens.  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;

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(b)           Excepted Liens;

(c)           Liens on Property securing the Debt under the Second Lien Term Loan Documents as permitted by the Intercreditor Agreement; provided, however, that (i) such Liens securing such Debt are subordinate to the Liens securing the Indebtedness pursuant to the Intercreditor Agreement and (ii) both before and after giving effect to the incurrence of any such Lien, the Borrower is in compliance with Section 8.14(c);

(d)           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;

(e)           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);

(f)            Liens on insurance proceeds securing Debt permitted by Section 9.02(h) of this Agreement;

(g)           [Intentionally Omitted]; and

(h)           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 (h) shall not exceed $6,000,000 at any time outstanding.

Section 9.04          Dividends, Distributions and Redemptions.

(a)           Restricted Payments.  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: (i) 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), (ii) each Subsidiary may make Restricted Payments to the Borrower and to any Subsidiaries of the Borrower that are Subsidiary Guarantors, (iii)(A) 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 (B) 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 (B), upon the death, termination or disability of such employee in an aggregate amount under this clause (B) not to exceed an amount equal to (1) $5,000,000 minus (2) the aggregate amount of cash Restricted Payments made in accordance with sub-clause (iii)(A), and, in any event, such amount shall be no less than $0, (iv) the Borrower may make Permitted Tax Distributions, (v) the Borrower may make Permitted Payments in an aggregate amount not to exceed $5,000,000 in

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any fiscal year, and (vi) 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, (A) Liquidity is greater than or equal to 10% of the Borrowing Base then in effect and (B) the Total Leverage Ratio, after giving pro forma effect to such Restricted Payment, is not greater than 3.50 to 1.00.

(b)           Redemption of Second Lien Notes; Amendment of Second Lien Term Loan Documents.  The Borrower will not, and will not permit any of the Subsidiary Guarantors to: (i) call, make or offer to make any optional or voluntary Redemption of or otherwise optionally or voluntarily Redeem (whether in whole or in part) the Second Lien Notes other than the optional Redemption in whole of such Second Lien Notes with the proceeds resulting from the first Senior Unsecured Debt Incurrence to occur after the Amendment No. 8 Effective Date, or (ii) amend, modify, waive or otherwise change, consent or agree to any amendment, modification, waiver or other change to, any of the terms of any Second Lien Term Loan Document if (A) the effect thereof would be to shorten the maturity of the Second Lien Notes or shorten the average life or increase the amount of any payment of principal thereof or increase the rate or add call or prepayment premiums or shorten any period for payment of interest thereon, (B)  such action adds additional Property as collateral to secure the Second Lien Notes unless the Borrower complies with Section 8.14(c) or (C) such action adds any covenants or defaults without this Agreement being contemporaneously amended to add (to the extent appropriate) substantially similar covenants or defaults.

Section 9.05          Investments, 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

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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)           [Intentionally Omitted];

(i)            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;

(j)            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(j) shall not exceed $1,000,000 in the aggregate at any time;

(k)           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(k) exceeds $500,000;

(l)            Investments in the form of Debt permitted under Section 9.02(f);

(m)          Investments in the form of Swap Agreements to the extent permitted under Section 9.17;

(n)           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 8.14(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

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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;

(o)           Investments permitted by Section 9.11 or Section 9.14;

(p)           Investments by the Borrower or a Subsidiary Guarantor in the Equity Interests of its Subsidiaries as of the date of this Agreement;

(q)           Investments by a Credit Party in CPD SPE required under the CPDA; and

(r)            other Investments made by the Borrower or any Subsidiary Guarantor not to exceed $35,000,000 in the aggregate at any time.

Section 9.06          Nature 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 9.07          [Intentionally Omitted.]

Section 9.08          Proceeds 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 9.09          ERISA 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.

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(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 9.10          Sale 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 9.11          Mergers, 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 9.12          Sale 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

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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 9.11;

(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 9.12); 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 9.12(l) shall not exceed $23,000,000.

Section 9.13          Transactions 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)

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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(j), (l), (p) or (q), and Investments to the extent permitted by Section 9.14; and (f) the payment of Acquisition Related Costs.

Section 9.14          Subsidiaries.  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 8.14(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 9.15          Negative 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, the Security Instruments, or the Second Lien Term Loan Documents) 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 (d), (f) or (g) 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(i) 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(i) specifying that dividends or distributions paid by any Subsidiary to holders of its Equity Interests shall be paid on a pro rata basis.

Section 9.16          Gas 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

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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 9.17          Swap Agreements.

(a)           Commodity Swap Agreements.

(i)            Incurrence.  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, shall not exceed for each month during the period during which such Swap Agreement is in effect, the lesser of (A) 100% of the Actual PDP Volumes, and (B) the volumes set forth in the grid below for the applicable period as determined by reference to the Reserve Report most recently delivered to the Administrative Agent; provided further that, the volume limitation in the foregoing proviso shall not prohibit the Borrower or any Subsidiary Guarantor from entering into Swap Agreements which, when taken together with all Swap Agreements then in effect, cover up to 100% of the Projected PDP Volumes:

Volumes Covered by Swap  Agreements	Applicable Period Covered By Swap  Agreements
70% of the anticipated projected production from proved Oil and Gas Properties	First 12 months after the “as of” date of the most recently delivered Reserve Report
60% of the anticipated projected production from proved Oil and Gas Properties	Months 13 — 24 after the “as of” date of the most recently delivered Reserve Report
50% of the anticipated projected production from proved Oil and Gas Properties	Months 25 — 36 after the “as of” date of the most recently delivered Reserve Report
40% of the anticipated projected production from proved Oil and Gas Properties	Months 37 — 60 after the “as of” date of the most recently delivered Reserve Report

(ii)           Maintenance.  The Borrower shall cause the average monthly Hedged Volume in each future 12-month period, at all times not to exceed 100% of the Actual PDP Volumes; provided that, if any such excess exists upon delivery of any Reserve Report to the Administrative Agent, no Event of Default shall exist as a result of such excess if, within 15 days after the Reserve Report is so delivered, the Borrower has effected, or has caused the applicable Subsidiary Guarantor to effect, such Swap Terminations necessary to eliminate such excess.

The requirements in clauses (i) and (ii) of this (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

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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.

(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.

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(d)           Acquisition Swap Agreements.

(i)            Notwithstanding anything in Section 9.17(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 9.17(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) subject to the following sentence, the aggregate notional volume of commodities covered under all of the Acquisition Swap Agreements with respect to any Subject Acquisition in any month, determined at the time such Acquisition Swap Agreement is entered into and after giving effect thereto, shall not exceed for each month during the period during which such Acquisition Swap Agreement is in effect, the lesser of (A) 100% of the monthly average of actual volume of production from such Target Oil and Gas Properties for the three-month period then ended, 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; provided further that, the volume limitation in the foregoing proviso shall not prohibit the Borrower or any Subsidiary Guarantor from entering into Acquisition Swap Agreements which, when taken together with all Acquisition Swap Agreements then in effect, cover up to 100% of the Projected Target Property PDP Volumes:

Volumes Covered by Acquisition Swap Agreements	Applicable Period Covered by Acquisition Swap Agreements
70% of the anticipated projected production from proved Target Oil and Gas Properties	First 12 months after acquisition of Target Oil and Gas Properties
60% of the anticipated projected production from proved Target Oil and Gas Properties	Months 13 — 24 after acquisition of Target Oil and Gas Properties
50% of the anticipated projected production from proved Target Oil and Gas Properties	Months 25 — 36 after acquisition of Target Oil and Gas Properties
40% of the anticipated projected production from proved Target Oil and Gas Properties	Months 37 — 60 after acquisition of Target Oil and Gas Properties

Notwithstanding the foregoing, the aggregate notional volume of commodities covered under all of the Acquisition Swap Agreements, determined at the time each Acquisition Swap Agreement is entered into, shall not exceed 50% of the aggregate notional volume of commodities that would otherwise be permitted to be covered under all Swap Agreements under Section 9.17(a) (without giving effect to, or including, any Target Oil and Gas Properties). The requirements in

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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 9.17(a) above, and (y) actual volumes of production from such Target Oil and Gas Properties shall not be included in any calculation of “Actual PDP Volumes” for purposes of determining compliance with Section 9.17(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 9.17(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 PDP 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(n).

Section 9.18          Change 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.

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(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 9.19          Parent 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

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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 9.19 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.

ARTICLE X
Events of Default; Remedies

Section 10.01       Events 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).

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(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(m) (as to its name or state of organization), Section 8.01(p), Section 8.02, Section 8.03 (with respect to its legal existence), Section 8.10(a), Section 8.16, 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)[Intentionally Omitted].

(h)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.

(i)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.

(j)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(i), (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

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general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing.

(k)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.

(l)(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.

(m)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.

(n)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.

(o)a Change in Control shall occur.

(p)The Intercreditor Agreement shall cease to be effective (other than pursuant to the terms provided therein or upon the full Redemption of the Second Lien Notes pursuant to Section 9.04(b)(i)) or otherwise shall cease to be a legal, valid and binding agreement enforceable against the holders of any Indebtedness under the Second Lien Credit Agreement in any material respect (other than as a result of the signatory for Wells Fargo Energy Capital, Inc. not having the proper corporate authority to execute and deliver the Intercreditor Agreement).

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Section 10.02Remedies.

(a)In the case of an Event of Default other than one described in Section 10.01(i), Section 10.01(j) or Section 10.01(k), 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(i), Section 10.01(j) or Section 10.01(k), 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

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(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

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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.  Each Lender and the Issuing Bank further (i) acknowledges that it has received a copy of the Intercreditor Agreement, (ii) acknowledges and agrees that the Administrative Agent is and was authorized to enter into the same, and (iii) agrees that it is bound by its terms.

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

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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.

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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, the Second Lien 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:

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(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 9.12 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).

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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 Section12.01(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

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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), (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

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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 8.14(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.

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(b)THE BORROWER SHALL 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 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,

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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 RELATING TO ANY OF THE FOREGOING, 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 BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO HAVE RESULTED FROM THE GROSS NEGLIGENCE, BAD FAITH OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE OR (II) SUCH CLAIMS (OTHER THAN CLAIMS AGAINST THE ADMINISTRATIVE AGENT, THE ARRANGER OR THE ISSUING BANK) ARE SOLELY BETWEEN INDEMNITEES.

Notwithstanding anything to the contrary in this (b), under no circumstances shall the provisions of this (b) be construed to cover any expenses not otherwise reimbursable under (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 (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

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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(h) 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:

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(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 (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

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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

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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, 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

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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.  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.

(c)Except as provided in Section 6.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter 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 telecopy 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

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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

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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

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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

108

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 “Obligations” 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

109

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, which information includes the name and address of the Borrower 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.

[SIGNATURES BEGIN NEXT PAGE]

110

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the Effective Date.

BORROWER:
JONES ENERGY HOLDINGS, LLC
By:
	Michael McConnell
	President

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

ADMINISTRATIVE AGENT/ ISSUING BANK/LENDER:
WELLS FARGO BANK,
NATIONAL ASSOCIATION
By:
	Paul Squires
	Managing Director

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:

CAPITAL ONE, NATIONAL ASSOCIATION

By:

Name:

Title:

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:
UNION BANK, N.A.
By:
	Haylee Dallas
	Vice President

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:

CREDIT AGRICOLE CORPORATE AND

           INVESTMENT BANK

By:

Name:

Title:

By:

Name:

Title:

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:
JPMORGAN CHASE BANK, N.A.
By:
	Ryan Aman
	Authorized Officer

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:

TORONTO DOMINION (NEW YORK) LLC

By:

Name:

Title:

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:

COMERICA BANK

By:

Name:

Title:

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

LENDER:

SUNTRUST BANK

By:

Name:

Title:

Signature Page to

Credit Agreement

(Jones Energy Holdings, LLC)

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Name of Lender	Applicable Percentage		Applicable Percentage of the Borrowing Base
Wells Fargo Bank, National Association	19.38775510204	%	$	193,877,551.02
Union Bank, N.A.	13.26530612245	%	$	132,653,061.22
Credit Agricole Corporate and Investment Bank	13.26530612245	%	$	132,653,061.22
Capital One, National Association	13.26530612245	%	$	132,653,061.22
JPMorgan Chase Bank, N.A.	13.26530612245	%	$	132,653,061.22
Toronto Dominion (New York) LLC	9.18367346939	%	$	91,836,734.70
Comerica Bank	9.18367346939	%	$	91,836,734.70
SunTrust Bank	9.18367346939	%	$	91,836,734.70
TOTAL	100.000000000	%	$	1,000,000,000.00

Annex A

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, 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.  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[  ]

1

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, 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.  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[  ]

2

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, 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 (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN 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[  ]

3

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, 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 (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN 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[  ]

4

EX-10.21

Exhibit 10.21

Execution Version

GUARANTEE AND COLLATERAL AGREEMENT

made by

Jones Energy, Inc.

in favor of

Wells Fargo Bank, N.A.,

as Administrative Agent

Dated as of January 29, 2014

TABLE OF CONTENTS

ARTICLE I Definitions		1
Section 1.01	Definitions	1
Section 1.02	Other Definitional Provisions; References	5
Section 1.03	Computation of Time Periods	5
ARTICLE II Guarantee		5
Section 2.01	Guarantee	5
Section 2.02	Payments	7
Section 2.03	Keepwell	7
ARTICLE III Grant of Security Interest		8
Section 3.01	Grant of Security Interest	8
Section 3.02	Transfer of Pledged Securities	10
Section 3.03	Grantor Remains Liable under Accounts, Chattel Paper and Payment Intangibles	10
ARTICLE IV Acknowledgments, Waivers and Consents		10
Section 4.01	Acknowledgments, Waivers and Consents	10
Section 4.02	No Subrogation, Contribution or Reimbursement	13
ARTICLE V Representations and Warranties		13
Section 5.01	Representations in Credit Agreement	13
Section 5.02	Benefit to the New Guarantor	13
Section 5.03	Title; No Other Liens	14
Section 5.04	Perfected First Priority Liens	14
Section 5.05	Legal Name, Organizational Status, Chief Executive Office	14
Section 5.06	Prior Names	14
Section 5.07	Pledged Securities	14
Section 5.08	Goods	15
Section 5.09	Instruments and Chattel Paper	15
Section 5.10	Truth of Information; Accounts	15
Section 5.11	Governmental Obligors	15
ARTICLE VI Covenants		15
Section 6.01	Maintenance of Perfected Security Interest; Further Documentation	15
Section 6.02	Maintenance of Records	16
Section 6.03	Changes in Locations, Name, etc.	16
Section 6.04	Limitations on Dispositions of Collateral	17
Section 6.05	Pledged Securities	17
Section 6.06	Analysis of Accounts, Etc.	18
Section 6.07	Instruments and Tangible Chattel Paper	18
Section 6.08	Commercial Tort Claims	18
ARTICLE VII Remedial Provisions		19
Section 7.01	Pledged Securities	19

i

Section 7.02	Collections on Accounts, Etc.	20
Section 7.03	Proceeds	20
Section 7.04	UCC and Other Remedies	21
Section 7.05	Private Sales of Pledged Securities	22
Section 7.06	Waiver; Deficiency	22
Section 7.07	Non-Judicial Enforcement	22
ARTICLE VIII The Administrative Agent		23
Section 8.01	Administrative Agent’s Appointment as Attorney-in-Fact, Etc.	23
Section 8.02	Duty of Administrative Agent	24
Section 8.03	Execution of Financing Statements	25
Section 8.04	Authority of Administrative Agent	25
ARTICLE IX Subordination of Indebtedness		25
Section 9.01	Subordination of All Guarantor Claims	25
Section 9.02	Claims in Bankruptcy	26
Section 9.03	Payments Held in Trust	26
Section 9.04	Liens Subordinate	26
Section 9.05	Notation of Records	26
ARTICLE X Miscellaneous		27
Section 10.01	Waiver	27
Section 10.02	Notices	27
Section 10.03	Payment of Expenses, Indemnities, Etc.	27
Section 10.04	Amendments in Writing	28
Section 10.05	Successors and Assigns	28
Section 10.06	Invalidity	28
Section 10.07	Counterparts	28
Section 10.08	Survival	28
Section 10.09	Captions	29
Section 10.10	Governing Law; Submission to Jurisdiction	29
Section 10.11	Acknowledgments	30
Section 10.12	Set-Off	31
Section 10.13	Releases	31
Section 10.14	Reinstatement	32
Section 10.15	Acceptance	32
Section 10.16	No Oral Agreements	32

SCHEDULES:

1.Notice Addresses of New Guarantor

2.Commercial Tort Claims

3.Filings and Other Actions Required to Perfect Security Interests

ii

4.Legal Name, Location of Jurisdiction of Organization, Organizational Identification Number, Taxpayer Identification Number and Chief Executive Office

5.Prior Names, Prior Chief Executive Office, Location of Tangible Assets

iii

This GUARANTEE AND COLLATERAL AGREEMENT, dated as of January 29, 2014, is made by Jones Energy, Inc., a Delaware corporation (the “Grantor”), in favor of Wells Fargo Bank, N.A., as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”), for the ratable benefit of the Secured Parties (such capitalized term and other capitalized terms used in this Agreement as hereinafter defined).

WHEREAS, pursuant to that certain Credit Agreement dated as of December 31, 2009 (as heretofore amended and as further amended, supplemented, amended and restated or otherwise modified from time to time, the “Credit Agreement”), by and among the Jones Energy Holdings, LLC, a Delaware limited liability company (the “Borrower”), each lender from time to time party thereto (collectively, the “Lenders” and individually, a “Lender”) and the Administrative Agent, the Lenders have extended Commitments to make Loans to the Borrower and to participate in Letters of Credit issued thereunder; and

WHEREAS, the Borrower and certain of its Subsidiaries have entered into that certain Guarantee and Collateral Agreement dated as of December 31, 2009 (as heretofore amended and supplemented, and as further amended, supplemented, amended and restated, or otherwise modified from time to time, the “Existing GCA”);

WHEREAS, the Borrower desires to amend the Credit Agreement pursuant to an Agreement and Amendment No. 8 to Credit Agreement (the “Amendment”) by and among the Borrower, the Grantor, the Administrative Agent and the Lenders party thereto;

WHEREAS, in connection with the Amendment, the Grantor is required to execute and deliver this Agreement;

WHEREAS, the Borrower has entered into or may enter into certain Permitted Swap Agreements; and

WHEREAS, the Borrower has entered into arrangements for or may enter into arrangements for certain Bank Products pursuant to the terms of the Credit Agreement;

NOW, THEREFORE, in consideration of the premises and to induce the Administrative Agent and the Lenders to enter into the Amendment and to continue to perform their respective obligations under the Credit Agreement and to induce the Secured Parties to make their respective extensions of credit to the Borrower thereunder and the extension of financial accommodations under the Permitted Swap Agreements and with respect to the Bank Products referred to above, the Grantor hereby agrees with the Administrative Agent, for the ratable benefit of the Secured Parties, as follows:

ARTICLE I
Definitions

Section 1.01Definitions.

(a)As used in this Agreement, each term defined above shall have the meaning indicated above.  Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement, and

the following terms as well as all uncapitalized terms which are defined in the UCC (as defined below) on the date hereof are used herein as so defined:  Accounts, Chattel Paper, Commercial Tort Claims, Deposit Accounts, Documents, Electronic Chattel Paper, Equipment, Fixtures, General Intangibles, Goods, Instruments, Inventory, Investment Property, Letter-of-Credit Rights, Payment Intangibles, Proceeds, Supporting Obligations, and Tangible Chattel Paper.

(b)The following terms shall have the following meanings:

“Account Debtor” shall mean a Person (other than the Grantor) obligated on an Account, Chattel Paper, or General Intangible.

“Agreement” shall mean this Guarantee and Collateral Agreement, as the same may be amended, supplemented or otherwise modified from time to time.

“Cash Collateral Accounts” shall mean all Deposit Accounts held with the Administrative Agent as cash collateral pursuant to Section 2.08(j) of the Credit Agreement.

“Collateral” shall have the meaning assigned such term in Section 3.01.

“Competing Guaranty” shall have the meaning assigned such term in Section 2.01(b)(i)(C).

“Contracts” shall mean all contracts to which the Grantor now is, or hereafter will be bound, or to which the Grantor is or hereafter will be a party, beneficiary or assignee and all exhibits, schedules and other attachments to such contracts, as the same may be amended, supplemented or otherwise modified or replaced from time to time.

“Contract Documents” shall mean all Instruments, Chattel Paper, letters of credit, bonds, guarantees or similar documents evidencing, representing, arising from or existing in respect of, relating to, securing or otherwise supporting the payment of, the Contract Rights.

“Contract Rights” shall mean (i) all (A) of the Grantor’s rights to payment under any Contract or Contract Document and (B) payments due and to become due to the Grantor under any Contract or Contract Document, in each case whether as contractual obligations, damages or otherwise; (ii) all of the Grantor’s claims, rights, powers, or privileges and remedies under any Contract or Contract Document; and (iii) all of the Grantor’s rights under any Contract or Contract Document to make determinations, to exercise any election (including, but not limited to, election of remedies) or option or to give or receive any notice, consent, waiver or approval together with full power and authority with respect to any Contract or Contract Document to demand, receive, enforce or collect any of the foregoing rights or any property which is the subject of any Contract or Contract Document, to enforce or execute any checks, or other instruments or orders, to file any claims and to take any action which, in the opinion of the Administrative Agent, may be necessary or advisable in connection with any of the foregoing.

“Dollars” refers to lawful money of the United States of America.

“Excluded Accounts” shall have the meaning assigned such term in Section 3.01(b).

2

“Excluded Certificated Collateral” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Contracts” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Equity” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Governmental Permits” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Perfection Assets” shall mean, collectively, any Property (a) in which a security interest cannot be perfected by the filing of a financing statement under the UCC and (b) with respect to which the Administrative Agent has determined, and continues to maintain, in its reasonable discretion that the cost of perfecting a security interest in such Property outweighs any benefit that would be received by the Secured Parties therefrom; provided that any such Property shall immediately and automatically cease to constitute “Excluded Perfection Assets” if, at any time, the Administrative Agent determines in its reasonable discretion that the cost of perfecting a security interest in such Property no longer outweighs the benefit that would be received by the Secured Parties therefrom.

“Excluded PMSI Collateral” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Real Property” shall have the meaning assigned such term in Section 3.01(b).

“Excluded Securities” shall mean the Equity Interests of Borrower and the certificates or instruments, if any, representing such Equity Interests.

“Exempt Goods” shall have the meaning assigned such term in Section 5.08.

“Exempt Instruments and Chattel Paper” shall have the meaning assigned such term in Section 5.09.

“Existing Grantors” shall mean, collectively, the Existing Guarantors and the Borrower.

“Existing Guarantors” shall mean, collectively, each Subsidiary that is, or becomes, party to the Existing GCA.

 “Foreign Subsidiary” shall have the meaning assigned such term in Section 3.01(b).

“Governmental Permits” shall mean any franchise, permit, certificate, license or authorization of any Governmental Authority.

“Guarantors” shall mean, collectively, the Existing Guarantors and the New Guarantor.

“Issuers” means, collectively, each issuer of a Pledged Security.

“New Guarantor” shall mean the Grantor.

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“Obligations” shall mean, collectively, all Indebtedness, liabilities and obligations of the Borrower and each Guarantor to the Secured Parties, of whatsoever nature and howsoever evidenced, due or to become due, now existing or hereafter arising, whether direct or indirect, absolute or contingent, which may arise under, out of, or in connection with the Credit Agreement, the other Loan Documents, any agreements, instruments or other documents entered into for the provision of Bank Products, and any Permitted Swap Agreements (provided that when any Hedge Bank ceases to be a Lender or an Affiliate of a Lender, “Obligations” shall include obligations under any Permitted Swap Agreement held by it only to the extent such obligations arise from transactions (i) entered into at the time that such Hedge Bank was a Lender or an Affiliate of a Lender or (ii) entered into on or prior to the Effective Date by a Person or an Affiliate of a Person that is a Lender on the Effective Date), and any amendment, restatement or modification of any of the foregoing, including, but not limited to, the full and punctual payment when due of any unpaid principal of the Loans and LC Exposure, any amounts payable in respect of an early termination under any Permitted Swap Agreement, interest (including, without limitation, interest accruing at any post-default rate and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding), fees, reimbursement obligations, guaranty obligations, penalties, indemnities, legal and other fees, charges and expenses, and amounts advanced by and expenses incurred in order to preserve any collateral or security interest, whether due after acceleration or otherwise.  Notwithstanding anything to the contrary contained herein or in any other Loan Document, (A) no Hedge Obligations and no Bank Product Obligations shall be “Obligations” 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 in the Credit Agreement and (B) no Excluded Swap Obligations shall be “Obligations”.

“Permitted Swap Agreement” shall mean any Swap Agreement entered into by any Existing Grantor with any Hedge Bank.

“Pledged Securities” shall mean: (i) all of Grantor’s interest in the Equity Interest of any Person (other than the Excluded Securities); and (ii) (a) the certificates or instruments, if any, representing such Equity Interests, (b) all dividends (cash, stock or otherwise), cash, instruments, rights to subscribe, purchase or sell and all other rights and property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such Equity Interests, (c) all replacements, additions to and substitutions for any of the property referred to in this definition, including, without limitation, claims against third parties, (d) the proceeds, interest, profits and other income of or on any of the property referred to in this definition and (e) all books and records relating to any of the property referred to in this definition.

“Secured Parties” shall mean, collectively, the Administrative Agent, the Lenders, the Hedge Banks, and Wells Fargo and any of its Affiliates providing Bank Products to any Credit Party.

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“Securities Act” shall mean the Securities Act of 1933, as amended.

“Security Termination” shall mean such time at which each of the following events shall have occurred on or prior to such time: (a) all Commitments have terminated or expired, (b) the Credit Agreement has terminated, (c) all Obligations (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) have been paid in full in cash, and (d) 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 in the Credit Agreement.

“UCC” shall mean the Uniform Commercial Code, as it may be amended, from time to time in effect in the State of Texas; provided, however, in the event that, by reason of mandatory provisions of law, any or all of the attachment, perfection or priority of the security interest in any Collateral is governed by the Uniform Commercial Code as in effect in a jurisdiction other than the State of Texas, the term “UCC” shall mean the Uniform Commercial Code as in effect in such other jurisdiction for purposes of the provisions hereof relating to such attachment, perfection or priority and for purposes of definitions related to such provisions.

Section 1.02Other Definitional Provisions; References.  The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.  The gender of all words shall include the masculine, feminine, and neuter, as appropriate.  The words “herein,” “hereof,” “hereunder” and other words of similar import when used in this Agreement refer to this Agreement as a whole, and not to any particular article, section or subsection.  Any reference herein to a Section shall be deemed to refer to the applicable Section of this Agreement unless otherwise stated herein.  Any reference herein to an exhibit, schedule or annex shall be deemed to refer to the applicable exhibit, schedule or annex attached hereto unless otherwise stated herein.  Where the context requires, terms relating to the Collateral or any part thereof, when used in relation to a Grantor, shall refer to such Grantor’s Collateral or the relevant part thereof.

Section 1.03Computation of Time Periods.  In this Agreement, with respect to the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each means “to but excluding.”

ARTICLE II
Guarantee

Section 2.01Guarantee.

(a)The New Guarantor hereby, unconditionally and irrevocably, guarantees to the Administrative Agent, for the ratable benefit of the Secured Parties and each of their respective permitted successors, endorsees, transferees and assigns, the prompt and complete payment and performance by the Borrower and the Guarantors when due (whether at the stated maturity, by acceleration or otherwise) of the Obligations.  This is a guarantee of payment and not collection and the liability of the New Guarantor is primary and not secondary.

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(b)Anything contained in this Agreement to the contrary notwithstanding, the obligations of the New Guarantor under this Agreement on any date shall be limited to a maximum aggregate amount equal to the largest amount that would not, on such date, render its obligations hereunder subject to avoidance as a fraudulent transfer or conveyance under Section 548 of the Bankruptcy Code of the United States or any applicable provisions of comparable laws relating to bankruptcy, insolvency, or reorganization, or relief of debtors (collectively, the “Fraudulent Transfer Laws”), but only to the extent that any Fraudulent Transfer Law has been found in a final non-appealable judgment of a court of competent jurisdiction to be applicable to such obligations as of such date, in each case

(i)after giving effect to all liabilities of the New Guarantor, contingent or otherwise, that are relevant under the Fraudulent Transfer Laws, but specifically excluding:

(A)any liabilities of the New Guarantor in respect of intercompany indebtedness to the Borrower or other affiliates of the Borrower to the extent that such indebtedness would be discharged in an amount equal to the amount paid by the New Guarantor hereunder;

(B)any liabilities of the New Guarantor under this Agreement; and

(C)any liabilities of the New Guarantor under each of its other guarantees of and joint and several co-borrowings of Debt, in each case entered into on the date this Agreement becomes effective, which contain a limitation as to maximum amount substantially similar to that set forth in this Section 2.01(b) (each such other guarantee and joint and several co-borrowing entered into on the date this Agreement becomes effective, a “Competing Guaranty”) to the extent the New Guarantor’s liabilities under such Competing Guaranty exceed an amount equal to (x) the aggregate principal amount of the New Guarantor’s obligations under such Competing Guaranty (notwithstanding the operation of that limitation contained in such Competing Guaranty that is substantially similar to this Section 2.01(b)), multiplied by (y) a fraction (I) the numerator of which is the aggregate principal amount of the New Guarantor’s obligations under such Competing Guaranty (notwithstanding the operation of that limitation contained in such Competing Guaranty that is substantially similar to this Section 2.01(b)), and (II) the denominator of which is the sum of (A) the aggregate principal amount of the obligations of the New Guarantor under all other Competing Guaranties (notwithstanding the operation of those limitations contained in such other Competing Guaranties that are substantially similar to this Section 2.01(b)), (B) the aggregate principal amount of the obligations of the New Guarantor under this Agreement (notwithstanding the operation of this Section 2.01(b)), and (C) the aggregate principal amount of the obligations of the New Guarantor under such Competing Guaranty (notwithstanding the operation of that limitation contained in such Competing Guaranty that is substantially similar to this Section 2.01(b)); and

(ii)after giving effect as assets to the value (as determined under the applicable provisions of the Fraudulent Transfer Laws) of any rights to subrogation, reimbursement, indemnification or contribution of the New Guarantor pursuant to applicable law or pursuant to the terms of any agreement.

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(c)The New Guarantor agrees that the Obligations may at any time and from time to time exceed the amount of the liability of the New Guarantor hereunder without impairing the guarantee contained in this Article II or affecting the rights and remedies of the Administrative Agent or any Secured Party hereunder.

(d)The New Guarantor agrees that if the maturity of any of the Obligations is accelerated by bankruptcy or otherwise, such maturity shall also be deemed accelerated for the purpose of this guarantee without demand or notice to the New Guarantor.  The guarantee contained in this Article II shall remain in full force and effect until Security Termination has occurred, notwithstanding that from time to time during the term of the Credit Agreement, no Obligations may be outstanding.

(e)No payment made by the Borrower, any of the Guarantors, any other guarantor or any other Person or received or collected by the Administrative Agent or any other Secured Party from the Borrower, any of the Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of the Obligations shall be deemed to modify, reduce, release or otherwise affect the liability of the New Guarantor hereunder which shall, notwithstanding any such payment (other than any payment made by the New Guarantor in respect of the Obligations or any payment received or collected from the New Guarantor in respect of the Obligations), remain liable for the Obligations up to the maximum liability of the New Guarantor hereunder until Security Termination has occurred.

Section 2.02Payments.  The New Guarantor hereby agrees and guarantees that payments hereunder will be paid to the Administrative Agent without set-off or counterclaim in Dollars at the principal office of the Administrative Agent specified pursuant to the Credit Agreement.

Section 2.03Keepwell.  To the extent that the New Guarantor is a Qualified ECP Guarantor, it hereby 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 or the Existing GCA, in each instance, in respect of Swap Obligations (provided, however, that the New Guarantor, to the extent it is a Qualified ECP Guarantor, shall only be liable under this Section 2.03 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 2.03, 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 the New Guarantor, to the extent it is a Qualified ECP Guarantor, under this Section 2.03 shall remain in full force and effect until the Security Termination has occurred.  The New Guarantor, to the extent it is a Qualified ECP Guarantor, intends that this Section 2.03 constitute, and this Section 2.03 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.

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ARTICLE III
Grant of Security Interest

Section 3.01Grant of Security Interest.

(a)The Grantor hereby pledges, assigns and transfers to the Administrative Agent, and grants to the Administrative Agent, for the ratable benefit of the Secured Parties, a security interest in all of the following property now owned or at any time hereafter acquired by the Grantor or in which the Grantor now has or at any time in the future may acquire any right, title or interest and whether now existing or hereafter coming into existence (collectively, the “Collateral”), as collateral security for the prompt and complete payment and performance when due (whether at the stated maturity, by acceleration or otherwise) of the Obligations:

(1)all Accounts;

(2)all Chattel Paper (whether Tangible Chattel Paper or Electronic Chattel Paper);

(3)all Commercial Tort Claims described on Schedule 2 hereto;

(4)all Cash Collateral Accounts;

(5)all Documents;

(6)all General Intangibles (including, without limitation, rights in and under any Swap Agreements);

(7)all Goods (including, without limitation, all Inventory and all Equipment, but excluding all Fixtures);

(8)all Instruments;

(9)all Investment Property;

(10)all Letter-of-Credit Rights (whether or not the letter of credit is evidenced by a writing;

(11)all Pledged Securities;

(12)all Supporting Obligations;

(13)all books and records pertaining to the Collateral; and

(14)to the extent not otherwise included, all Proceeds and products of any and all of the foregoing and all collateral security, guarantees and other Supporting Obligations given with respect to any of the foregoing.

(b)Notwithstanding anything to the contrary contained in Section 3.01(a) and other than to the extent set forth in this Section 3.01(b), the following property shall be excluded

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from the lien and security interest granted hereunder (and shall, as applicable, not be included as “Collateral”, “Inventory”, “Equipment”, “General Intangibles”, “Investment Property”, “Proceeds”, “Instruments” or “Chattel Paper” for the purposes of this Agreement): (i) any Contract, Contract Document or other document (and any Contract Rights arising thereunder) to which the Grantor is a party on the date hereof and any Governmental Permit held by the Grantor, in any case to the extent (but only to the extent) that the Grantor is prohibited from granting a security interest in, pledge of, or charge, mortgage or lien upon any such Property by reason of (A) an existing and enforceable negative pledge or anti-assignment provision or (B) any Governmental Requirement to which the Grantor or its property is subject (all such Contracts, Contract Documents, and other documents being the “Excluded Contracts”) and all such Governmental Permits being the “Excluded Governmental Permits”); provided, however, that (x) the exclusion from the lien and security interest granted by the Grantor hereunder of any Contract Rights or Governmental Permit of the Grantor under one or more of the Excluded Contracts or Excluded Governmental Permits shall not limit, restrict or impair the grant by the Grantor of the lien and security interest in any Accounts or receivables arising under any such Excluded Contract or Excluded Governmental Permits or any payments due or to become due thereunder, and (y) any Excluded Contract or Excluded Governmental Permit shall automatically cease to be excluded from this Section 3.01(b) (and shall automatically be subject to the lien and security interest granted hereby and to the terms and provisions of this Agreement as “Collateral”), to the extent that (1) either of the prohibitions discussed in clause (A) and (B) above is ineffective or subsequently rendered ineffective under Sections 9.406, 9.407, 9.408 or 9.409 of the UCC or under any other Governmental Requirement or is otherwise no longer in effect, or (2) the Grantor has obtained the consent of the other parties to such Excluded Contract to the creation of a lien and security interest in, such Excluded Contract; (ii) as to the Grantor, more than 65% of the outstanding voting stock of (A) any entity that is a controlled foreign corporation under Section 957 of the Internal Revenue Code (or any successor provision thereto) (“Foreign Subsidiary”) and (B) any Subsidiary of the Grantor that has no Property other than Equity Interests in Foreign Subsidiaries (any such stock being the “Excluded Equity”); (iii) any property of the Grantor that is now or hereafter subject to a Lien securing Debt to the extent (and only to the extent) that (A) such Lien is permitted by Section 9.19 of the Credit Agreement and such Debt is permitted by Section 9.02(b) of the Credit Agreement, and (B) the documents evidencing such Debt prohibit the granting of a Lien in the property securing such Debt (all such property being the “Excluded PMSI Collateral”); (iv) the Grantor’s real property interests, including real leasehold interests (all such property being the “Excluded Real Property”); (v) any Deposit Account (other than Cash Collateral Accounts), securities account or commodity hedging account, and any property in such accounts from time to time (all such property being the “Excluded Accounts”); (vi) any motor vehicles, aircraft, rolling stock or other assets subject to certificate-of-title statutes (excluding, for the avoidance of doubt, Oil and Gas Properties) (all such property being the “Excluded Certificated Collateral”); and (vii) the Excluded Securities; provided, however, that any Proceeds received by any Grantor on account of any Excluded Contracts, Excluded Governmental Permits, Excluded Equity, Excluded PMSI Collateral, Excluded Real Property, Excluded Accounts, Excluded Certificated Collateral, Excluded Securities or any other Property excluded under clauses (i) through (vii) above shall constitute Collateral unless any assets or Property constituting such Proceeds are themselves subject to the exclusions set forth in clauses (i) through (vii) above.

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Section 3.02Transfer of Pledged Securities.  All certificates and instruments representing or evidencing the Pledged Securities shall be delivered to and held pursuant hereto by the Administrative Agent or a Person designated by the Administrative Agent and, in the case of an instrument or certificate in registered form, shall be duly indorsed to the Administrative Agent or in blank by an effective indorsement (whether on the certificate or instrument or on a separate writing), and accompanied by any required transfer tax stamps to effect the pledge of the Pledged Securities to the Administrative Agent.  Notwithstanding the preceding sentence, all Pledged Securities must be delivered or transferred in such manner, and the Grantor shall take all such further action as may be requested by the Administrative Agent, as to permit the Administrative Agent to be a “protected purchaser” to the extent of its security interest as provided in Section 8.303 of the UCC (if the Administrative Agent otherwise qualifies as a protected purchaser). Grantor Remains Liable under Accounts, Chattel Paper and Payment Intangibles.  Anything herein to the contrary notwithstanding, the Grantor shall remain liable under each of the Accounts, Chattel Paper and Payment Intangibles to observe and perform all the conditions and obligations to be observed and performed by it thereunder, to the same extent as if this Agreement had not been executed.  Neither the Administrative Agent nor any other Secured Party shall have any obligation or liability under any Account, Chattel Paper or Payment Intangible (or any agreement giving rise thereto) by reason of or arising out of this Agreement or the receipt by the Administrative Agent or any such other Secured Party of any payment relating to such Account, Chattel Paper or Payment Intangible, pursuant hereto, nor shall the Administrative Agent or any other Secured Party be obligated in any manner to perform any of the obligations of the Grantor under or pursuant to any Account, Chattel Paper or Payment Intangible (or any agreement giving rise thereto), to make any payment, to make any inquiry as to the nature or the sufficiency of any payment received by it or as to the sufficiency of any performance by any party under any Account, Chattel Paper or Payment Intangible (or any agreement giving rise thereto), to present or file any claim, to take any action to enforce any performance or to collect the payment of any amounts which may have been assigned to it or to which it may be entitled at any time or times.

ARTICLE IV
Acknowledgments, Waivers and Consents

Section 4.01Acknowledgments, Waivers and Consents.

(a)The Grantor acknowledges and agrees that the obligations undertaken by it under this Agreement involve the guarantee and the provision of collateral security for the obligations of Persons other than the Grantor and that until Security Termination has occurred the Grantor’s guarantee and provision of collateral security for the Obligations are absolute, irrevocable and unconditional under any and all circumstances.  In full recognition and furtherance of the foregoing, the Grantor understands and agrees, to the fullest extent permitted under applicable law and except as may otherwise be expressly and specifically provided in the Loan Documents, that the Grantor shall remain obligated hereunder (including, without limitation, with respect to the guarantee made by the Grantor hereby and the collateral security provided by the Grantor herein) and the enforceability and effectiveness of this Agreement and the liability of the Grantor, and the rights, remedies, powers and privileges of the Administrative Agent and the other Secured Parties under this Agreement and the other Loan Documents shall not be affected, limited, reduced, discharged or terminated in any way:

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(i)notwithstanding that, without any reservation of rights against the Grantor and without notice to or further assent by the Grantor, (A) any demand for payment of any of the Obligations made by the Administrative Agent or any other Secured Party may be rescinded by the Administrative Agent or such other Secured Party and any of the Obligations continued; (B) the Obligations, the liability of any other Person upon or for any part thereof or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, surrendered or released by, or any indulgence or forbearance in respect thereof granted by, the Administrative Agent or any other Secured Party; (C) the Credit Agreement, the other Loan Documents, any Permitted Swap Agreement and any other documents executed and delivered in connection therewith may be amended, modified, supplemented or terminated, in whole or in part, as the Administrative Agent (or the Required Lenders, the Majority Lenders or all Lenders, as the case may be) may deem advisable from time to time; (D) the Borrower, any the Grantor or any other Person may from time to time accept or enter into new or additional agreements, security documents, guarantees or other instruments in addition to, in exchange for or relative to, any Loan Document or any Permitted Swap Agreement, all or any part of the Obligations or any Collateral now or in the future serving as security for the Obligations; (E) any collateral security, guarantee or right of offset at any time held by the Administrative Agent or any other Secured Party for the payment of the Obligations may be sold, exchanged, waived, surrendered or released; and (F) any other event (other than Security Termination) shall occur which constitutes a defense or release of sureties generally; and

(ii)without regard to, and the Grantor hereby expressly waives to the fullest extent permitted by law any defense now or in the future arising by reason of, (A) the illegality, invalidity or unenforceability of the Credit Agreement, any other Loan Document, any Permitted Swap Agreement, any of the Obligations or any other collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by the Administrative Agent or any other Secured Party, (B) any defense, set-off or counterclaim (other than a defense of payment or performance) which may at any time be available to or be asserted by the Grantor or any other Person against the Administrative Agent or any other Secured Party, (C) the insolvency, bankruptcy arrangement, reorganization, adjustment, composition, liquidation, disability, dissolution or lack of power of the Grantor or any other Person at any time liable for the payment of all or part of the Obligations or the failure of the Administrative Agent or any other Secured Party to file or enforce a claim in bankruptcy or other proceeding with respect to any Person; or any sale, lease or transfer of any or all of the assets of the Grantor, or any changes in the shareholders of the Grantor; (D) the fact that any Collateral or Lien contemplated or intended to be given, created or granted as security for the repayment of the Obligations shall not be properly perfected or created, or shall prove to be unenforceable or subordinate to any other Lien, it being recognized and agreed by the Grantor that it is not entering into this Agreement in reliance on, or in contemplation of the benefits of, the validity, enforceability, collectability or value of any of the Collateral for the Obligations; (E) any failure of the Administrative Agent or any other Secured Party to marshal assets in favor of the Grantor or any other Person, to exhaust any collateral for all or any part of the Obligations, to pursue or exhaust any right, remedy, power or privilege it may have against the Grantor or any other Person or to take any action whatsoever to mitigate or reduce the Grantor’s liability under this Agreement or any other Loan Document; (F) any law which provides that the obligation of a

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surety or guarantor must neither be larger in amount nor in other respects more burdensome than that of the principal or which reduces a surety’s or guarantor’s obligation in proportion to the principal obligation; (G) the possibility that the Obligations may at any time and from time to time exceed the aggregate liability of the Grantor under this Agreement; or (H) any other circumstance or act whatsoever, which constitutes, or might be construed to constitute, an equitable or legal discharge or defense of the Borrower for the Obligations, or of the Grantor under the guarantee contained in Article II or with respect to the collateral security provided by the Grantor herein, or which might be available to a surety or guarantor, in bankruptcy or in any other instance.

(b)The Grantor hereby waives to the extent permitted by law:  (i) except as expressly provided otherwise in any Loan Document, all notices to the Grantor, or to any other Person, including but not limited to, notices of the acceptance of this Agreement, the guarantee contained in Article II or the provision of collateral security provided herein, or the creation, renewal, extension, modification, accrual of any Obligations, or notice of or proof of reliance by the Administrative Agent or any other Secured Party upon the guarantee contained in Article II or upon the collateral security provided herein, or of default in the payment or performance of any of the Obligations owed to the Administrative Agent or any other Secured Party and enforcement of any right or remedy with respect thereto; or notice of any other matters relating thereto; the Obligations, and any of them, shall conclusively be deemed to have been created, contracted or incurred, or renewed, extended, amended or waived, in reliance upon the guarantee contained in Article II and the collateral security provided herein and no notice of creation of the Obligations or any extension of credit already or hereafter contracted by or extended to the Borrower need be given to the Grantor; and all dealings between the Borrower, the other Existing Grantors, and the Grantor, on the one hand, and the Administrative Agent and the other Secured Parties, on the other hand, likewise shall be conclusively presumed to have been had or consummated in reliance upon the guarantee contained in Article II and on the collateral security provided herein; (ii) diligence and demand of payment, presentment, protest, dishonor and notice of dishonor; (iii) any statute of limitations affecting the Grantor’s liability hereunder or the enforcement thereof; (iv) all rights of revocation with respect to the Obligations, the guarantee contained in Article II and the provision of collateral security herein; and (v) all principles or provisions of law which conflict with the terms of this Agreement and which can, as a matter of law, be waived.

(c)When making any demand hereunder or otherwise pursuing its rights and remedies hereunder against the Grantor, the Administrative Agent or any other Secured Party may, but shall be under no obligation to, join or make a similar demand on or otherwise pursue or exhaust such rights and remedies as it may have against the Borrower, any other Existing Grantor or any other Person or against any collateral security or guarantee for the Obligations or any right of offset with respect thereto, and any failure by the Administrative Agent or any other Secured Party to make any such demand, to pursue such other rights or remedies or to collect any payments from the Borrower, any other Existing Grantor or any other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of the Borrower, any other Existing Grantor or any other Person or any such collateral security, guarantee or right of offset, shall not relieve the Grantor of any obligation or liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the Administrative Agent or any other Secured Party against the Grantor.  For

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the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.  Neither the Administrative Agent nor any other Secured Party shall have any obligation to protect, secure, perfect or insure any Lien at any time held by it as security for the Obligations or for the guarantee contained in Article II or any property subject thereto.

Section 4.02No Subrogation, Contribution or Reimbursement.  Notwithstanding any payment made by the Grantor hereunder or any set-off or application of funds of the Grantor by the Administrative Agent or any other Secured Party, the Grantor shall not be entitled to be subrogated to any of the rights of the Administrative Agent or any other Secured Party against the Borrower or the Grantor or any collateral security or guarantee or right of offset held by the Administrative Agent or any other Secured Party for the payment of the Obligations, nor shall the Grantor seek or be entitled to seek any indemnity, exoneration, participation, contribution or reimbursement from the Borrower or any other Existing Grantor in respect of payments made by the Grantor hereunder, and the Grantor hereby expressly waives, releases, and agrees not to exercise any and all such rights of subrogation, reimbursement, indemnity and contribution.  The Grantor further agrees that to the extent that such waiver and release set forth herein is found by a court of competent jurisdiction to be void or voidable for any reason, any rights of subrogation, reimbursement, indemnity and contribution the Grantor may have against the Borrower or against any collateral or security or guarantee or right of offset held by the Administrative Agent or any other Secured Party shall, until Security Termination has occurred, be junior and subordinate to any rights the Administrative Agent and the other Secured Parties may have against the Borrower and the Grantor and to all right, title and interest the Administrative Agent and the other Secured Parties may have in any collateral or security or guarantee or right of offset.  The Administrative Agent, for the benefit of the Secured Parties, may use, sell or dispose of any item of Collateral or security as it sees fit without regard to any subrogation rights the Grantor may have, and upon any disposition or sale, any rights of subrogation the Grantor may have shall terminate.

ARTICLE V
Representations and Warranties

To induce the Administrative Agent and the other Secured Parties to continue to perform their respective obligations under the Credit Agreement and to induce the Lenders to make their respective extensions of credit to the Borrower thereunder and to induce any Hedge Bank to continue to perform its obligations under any existing Permitted Swap Agreements and to enter into new Permitted Swap Agreements, the Grantor hereby represents and warrants to the Administrative Agent and each other Secured Party that:

Section 5.01Representations in Credit Agreement.  In the case of the New Guarantor, the representations and warranties set forth in Article VII of the Credit Agreement as they relate to the New Guarantor or to the Loan Documents to which the New Guarantor is a party are true and correct in all material respects, provided that each reference in each such representation and warranty to the Borrower’s knowledge shall, for the purposes of this Section 5.01, be deemed to be a reference to the New Guarantor’s knowledge.

Section 5.02Benefit to the New Guarantor.  The Borrower is a member of an affiliated group of companies that includes the New Guarantor, and the Borrower and the New Guarantor

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are engaged in related businesses.  The New Guarantor is an Affiliate of the Borrower and its guaranty and surety obligations pursuant to this Agreement reasonably may be expected to benefit, directly or indirectly, it; and it has determined that this Agreement is necessary and convenient to the conduct, promotion and attainment of the business of the New Guarantor and the Borrower.

Section 5.03Title; No Other Liens.  Except for the security interest granted to the Administrative Agent for the ratable benefit of the Secured Parties pursuant to this Agreement, the Grantor has good title to all its respective items of the Collateral, in each case, free and clear of all Liens except Liens permitted by the Credit Agreement.  No effective financing statement or other security instrument or recording with respect to all or any part of the Collateral is on file or of record in any public office, except such as have been filed in favor of the Administrative Agent, for the ratable benefit of the Secured Parties, pursuant to this Agreement, the Security Instruments or as are filed to secure Liens permitted by the Credit Agreement, or as to which a duly authorized termination statement relating to such financing statement or other instrument has been delivered to the Administrative Agent on or prior to the date hereof or with respect to which such Lien has been discharged by the Bankruptcy Court.

Section 5.04Perfected First Priority Liens.  The security interests granted pursuant to this Agreement (a) upon completion of the filings and other actions specified on Schedule 3 (which, in the case of all filings and other documents referred to on said Schedule, have been delivered to the Administrative Agent in completed and, if applicable, duly executed form) will constitute valid perfected security interests in all of the Collateral (other than Excluded Perfection Assets) in favor of the Administrative Agent, for the ratable benefit of the Secured Parties, as collateral security for the Obligations, enforceable in accordance with the terms hereof against all creditors of the Grantor and any Persons purporting to purchase any Collateral (other than Inventory sold in the ordinary course of business) from the Grantor and (b) are prior in right of priority to all other Liens on the Collateral in existence on the date hereof except for Excepted Liens that have priority over the Liens on the Collateral by operation of law and other Liens permitted under the Credit Agreement.

Section 5.05Legal Name, Organizational Status, Chief Executive Office.  On the date hereof, the correct legal name of the Grantor, the Grantor’s jurisdiction of organization, organizational number, taxpayer identification number and the location of the Grantor’s chief executive office are specified on Schedule 4.

Section 5.06Prior Names.  Schedule 5 correctly sets forth all names and trade names that the Grantor has used in the last five years.

Section 5.07Pledged Securities.  The shares (or such other interests) of Pledged Securities pledged by the Grantor hereunder constitute all the issued and outstanding shares (or such other interests) of all classes of the Equity Interests of each Issuer (other than the Borrower) owned by the Grantor.  All the shares (or such other interests) of the Pledged Securities have been duly and validly issued and are fully paid and nonassessable; and such Grantor is the record and beneficial owner of, and has good title to, the Pledged Securities pledged by it hereunder, free of any and all Liens or options in favor of any other Person, except the security interest created by this Agreement or any other Security Instrument, Liens on Property securing the Debt

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under the Second Lien Term Loan Documents to the extent such Liens are permitted under the Credit Agreement, and Excepted Liens. Goods.  No portion of the Collateral constituting Goods (other than Oil and Gas Properties) having an aggregate value in excess of $500,000 is in the possession of a bailee that has issued a negotiable or non-negotiable document covering such Collateral, except any such Collateral (other than Oil and Gas Properties) the aggregate value of which does not exceed $500,000 at any time (the “Exempt Goods”).

Section 5.09Instruments and Chattel Paper.  The Grantor has delivered to the Administrative Agent all Collateral constituting Instruments and Chattel Paper (other than Excluded Perfection Assets), except with respect to any such Collateral, the value of, individually or in the aggregate, does not exceed $500,000 (the “Exempt Instruments and Chattel Paper”).  No Collateral constituting Chattel Paper or Instruments contains any statement therein to the effect that such Collateral has been assigned to an identified party other than the Administrative Agent, and the grant of a security interest in such Collateral in favor of the Administrative Agent hereunder does not violate the rights of any other Person as a secured party.

Section 5.10Truth of Information; Accounts.  None of the information with respect to the Collateral set forth in any schedule, certificate or other writing at any time heretofore or hereafter furnished by the Grantor to the Administrative Agent or any other Secured Party, or any other information furnished by or on behalf of the Grantor to the Administrative Agent or any other Secured Party in connection with the negotiation of this Agreement or delivered hereunder, 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.  The place where the Grantor keeps its records concerning the Accounts, Chattel Paper and Payment Intangibles is set forth on Schedule 3.

Section 5.11Governmental Obligors.  None of the Account Debtors on the Grantor’s Accounts, Chattel Paper or Payment Intangibles is a Governmental Authority.

ARTICLE VI
Covenants

The Grantor covenants and agrees with the Administrative Agent and the other Secured Parties that, from and after the date of this Agreement until Security Termination has occurred:

Section 6.01Maintenance of Perfected Security Interest; Further Documentation.

(a)The Grantor shall maintain the security interest created by this Agreement as a perfected security interest having at least the priority described in Section 5.04 and shall defend such security interest against the claims and demands of all Persons whomsoever (other than to the extent such claims and demands are permitted by the Credit Agreement).

(b)At any time and from time to time, upon the request of the Administrative Agent or any other Secured Party, and at the sole expense of the Grantor, the Grantor will promptly and duly give, execute, deliver, indorse, file or record any and all financing statements, continuation statements, amendments, notices (including, without limitation, notifications to

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financial institutions and any other Person), contracts, agreements, assignments, certificates, stock powers or other instruments, obtain any and all governmental approvals and consents and take or cause to be taken any and all steps or acts that may be necessary or as the Administrative Agent may reasonably request to create, perfect (other than with respect to Excluded Perfection Assets), establish the priority of, or to preserve the validity, perfection (other than with respect to Excluded Perfection Assets) or priority of, the Liens granted by this Agreement or to enable the Administrative Agent or any other Secured Party to enforce its rights, remedies, powers and privileges under this Agreement with respect to such Liens or to otherwise obtain or preserve the full benefits of this Agreement and the rights, powers and privileges herein granted.

(c)Without limiting the obligations of the Grantor under Section 6.01(b), other than with respect to Collateral constituting Excluded Perfection Assets, Exempt Goods and Exempt Instruments and Chattel Paper:  (i) upon the request of the Administrative Agent, the Grantor shall take or cause to be taken all actions (other than any actions required to be taken by the Administrative Agent or any Secured Party) reasonably requested by the Administrative Agent to cause the Administrative Agent to (A) have “control” (within the meaning of Sections 9.104, 9.105, 9.106, and 9.107 of the UCC) over any Collateral constituting Electronic Chattel Paper, Investment Property (including the Pledged Securities), or Letter-of-Credit Rights, including, without limitation, executing and delivering any agreements, in form and substance reasonably satisfactory to the Administrative Agent, with securities intermediaries, issuers or other Persons in order to establish “control”, and the Grantor shall promptly notify the Administrative Agent and the other Secured Parties of the Grantor’s acquisition of any such Collateral, and (B) be a “protected purchaser” (as defined in Section 8.303 of the UCC); (ii) with respect to Collateral other than certificated securities and goods covered by a document in the possession of a Person other than the Grantor or the Administrative Agent, the Grantor shall obtain written acknowledgment that such Person holds possession for the Administrative Agent’s benefit; and (iii) with respect to any Collateral constituting Goods that are in the possession of a bailee, the Grantor shall provide prompt notice to the Administrative Agent and the other Secured Parties of any such Collateral then in the possession of such bailee, and the Grantor shall take or cause to be taken all actions (other than any actions required to be taken by the Administrative Agent or any other Secured Party) necessary or reasonably requested by the Administrative Agent to cause the Administrative Agent to have a perfected security interest in such Collateral under applicable law.

(d)This Section 6.01 and the obligations imposed on the Grantor by this Section 6.01 shall be interpreted as broadly as possible in favor of the Administrative Agent and the other Secured Parties in order to effectuate the purpose and intent of this Agreement.

Section 6.02Maintenance of Records.  The Grantor will keep and maintain at its own cost and expense reasonably satisfactory and complete records of the Collateral, including, without limitation, a record of all payments received and all credits granted with respect to the Accounts.

Section 6.03Changes in Locations, Name, etc.  The Grantor recognizes that financing statements pertaining to the Collateral have been or may be filed where the Grantor is organized.  Without limitation of any other covenant herein, the Grantor will not cause or permit (i) any change to be made in its name, identity or corporate structure or (ii) any change to the Grantor’s

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jurisdiction of organization, unless the Grantor shall have first (1) notified the Administrative Agent of such change at least ten (10) days (or such shorter period of time as may be reasonably acceptable to the Administrative Agent) prior to the effective date of such change, and (2) taken all action reasonably requested by the Administrative Agent for the purpose of maintaining the perfection and priority of the Administrative Agent’s security interests under this Agreement.

Section 6.04Limitations on Dispositions of Collateral.  The Administrative Agent and the other Secured Parties do not authorize, and the Grantor agrees not to Dispose of any of the Collateral, except to the extent permitted by the Credit Agreement.

Section 6.05Pledged Securities.

(a)If the Grantor shall become entitled to receive or shall receive any stock certificate or other instrument (including, without limitation, any certificate or instrument representing a dividend or a distribution in connection with any reclassification, increase or reduction of capital or any certificate or instrument issued in connection with any reorganization), option or rights in respect of the capital stock or other equity interests of any Issuer whether in addition to, in substitution of, as a conversion of, or in exchange for, any shares (or such other interests) of the Pledged Securities, or otherwise in respect thereof, the Grantor shall accept the same as the agent of the Administrative Agent and the other Secured Parties, hold the same in trust for the Administrative Agent and the other Secured Parties and deliver the same forthwith to the Administrative Agent in the exact form received, duly indorsed by the Grantor to the Administrative Agent, if required, together with an undated stock power or other equivalent instrument of transfer acceptable to the Administrative Agent covering such certificate or instrument duly executed in blank by the Grantor and with, if the Administrative Agent so requests, signature guaranteed, to be held by the Administrative Agent, subject to the terms hereof, as additional collateral security for the Obligations.

(b)Without the prior written consent of the Administrative Agent, the Grantor will not (except in each case as permitted by the Credit Agreement) (i) unless otherwise permitted hereby, vote to enable, or take any other action to permit, any Issuer to issue any Equity Interest of any nature or to issue any other securities or interests convertible into or granting the right to purchase or exchange for any Equity Interests of any nature of any Issuer, (ii) sell, assign, transfer, exchange or otherwise dispose of, or grant any option with respect to, the Pledged Securities or Proceeds thereof (except pursuant to a transaction expressly permitted by the Credit Agreement), (iii) create, incur or permit to exist any Lien or option in favor of, or any claim of any Person with respect to, any of the Pledged Securities or Proceeds thereof, or any interest therein, except the security interest created by this Agreement or any other Security Instrument, Liens on Property securing the Debt under the Second Lien Term Loan Documents to the extent such Liens are permitted under the Credit Agreement, and Excepted Liens or (iv) enter into any agreement or undertaking restricting the right or ability of the Grantor or the Administrative Agent to sell, assign or transfer any of the Pledged Securities or Proceeds thereof.

(c)The Grantor shall furnish to the Administrative Agent such stock powers and other equivalent instruments of transfer as may be required by the Administrative Agent to assure the transferability of and the perfection of the security interest in the Pledged Securities when and as often as may be reasonably requested by the Administrative Agent.

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(d)           The Pledged Securities will at all times constitute not less than 100% of the capital stock or other equity interests of the Issuer thereof owned by the Grantor.  The Grantor will not permit any Issuer of any of the Pledged Securities to issue any new shares (or other interests) of any class of capital stock or other equity interests of such Issuer without the prior written consent of the Administrative Agent.

Section 6.06          Analysis of Accounts, Etc.  Upon the occurrence and during the continuance of an Event of Default, the Administrative Agent shall have the right from time to time to make test verifications of the Accounts, Chattel Paper and Payment Intangibles in any manner and through any medium that it reasonably considers advisable, and the Grantor, at the Grantor’s sole cost and expense, shall furnish all such assistance and information as the Administrative Agent may require in connection therewith.  Upon the occurrence and during the continuance of an Event of Default, at any time and from time to time, upon the Administrative Agent’s request and at the expense of the Grantor, the Grantor shall furnish to the Administrative Agent reports showing reconciliations, aging and test verifications of, and trial balances for, the Accounts, Chattel Paper and Payment Intangibles, and all original and other documents evidencing, and relating to, the agreements and transactions which gave rise to the Accounts, Chattel Paper and Payment Intangibles, including, without limitation, all original orders, invoices and shipping receipts.

Section 6.07          Instruments and Tangible Chattel Paper.  If any amount payable under or in connection with any of the Collateral shall be or become evidenced by any Instrument or Tangible Chattel Paper (other than in each case Excluded Perfection Assets), such Instrument or Tangible Chattel Paper shall be immediately delivered to the Administrative Agent, duly endorsed in a manner satisfactory to the Administrative Agent, to be held as Collateral pursuant to this Agreement.

Section 6.08          Commercial Tort Claims.  If the Grantor shall at any time hold or acquire a Commercial Tort Claim that satisfies the requirements of the following sentence, the Grantor shall, within thirty (30) days from the date upon which such Commercial Tort Claim satisfies such requirements, notify the Administrative Agent in a writing signed by the Grantor containing a brief description thereof, and granting to the Administrative Agent in such writing (for the benefit of the Secured Parties) a security interest therein and in the Proceeds thereof, all upon the terms of this Agreement, with such writing to be in form and substance satisfactory to the Administrative Agent.  The provisions of the preceding sentence shall apply only to a Commercial Tort Claim that satisfies the following requirements:  (i) the monetary value claimed by or payable to the Grantor in connection with such Commercial Tort Claim shall exceed $500,000, and either (ii) (A) the Grantor shall have filed a lawsuit or counterclaim or otherwise commenced legal proceedings (including, without limitation, arbitration proceedings) against the Person against whom such Commercial Tort Claim is made, or (B) the Grantor and the Person against whom such Commercial Tort Claim is asserted shall have entered into a settlement agreement with respect to such Commercial Tort Claim.  In addition, to the extent that the existence of any Commercial Tort Claim held or acquired by the Grantor is disclosed by the Grantor in any public filing with the Securities Exchange Commission or any successor thereto or analogous Governmental Authority, or to the extent that the existence of any such Commercial Tort Claim is disclosed in any press release issued by the Grantor, then, upon the request of the Administrative Agent, the Grantor shall, within thirty (30) days from the date upon

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which such request is made, transmit to the Administrative Agent a writing signed by the Grantor containing a brief description of such Commercial Tort Claim and granting to the Administrative Agent in such writing (for the benefit of the Secured Parties) a security interest therein and in the Proceeds thereof, all upon the terms of this Agreement, with such writing to be in form and substance satisfactory to the Administrative Agent.

ARTICLE VII
Remedial Provisions

Section 7.01          Pledged Securities.

(a)           Unless an Event of Default shall have occurred and be continuing and the Administrative Agent shall have given notice to the Grantor of the Administrative Agent’s intent to exercise its corresponding rights pursuant to Section 7.01(b), the Grantor shall be permitted to receive all cash dividends paid in respect of the Pledged Securities, to the extent permitted in the Credit Agreement, and to exercise all voting and corporate rights with respect to the Pledged Securities.

(b)           If an Event of Default shall occur and be continuing, then at any time in the Administrative Agent’s discretion without notice, (i) the Administrative Agent shall have the right to receive any and all cash dividends, payments or other Proceeds paid in respect of the Pledged Securities and make application thereof to the Obligations in accordance with Section 10.02 of the Credit Agreement, and (ii) any or all of the Pledged Securities shall be registered in the name of the Administrative Agent or its nominee, and the Administrative Agent or its nominee may thereafter exercise (x) all voting, corporate and other rights pertaining to such Pledged Securities at any meeting of shareholders (or other equivalent body) of the relevant Issuer or Issuers or otherwise and (y) any and all rights of conversion, exchange and subscription and any other rights, privileges or options pertaining to such Pledged Securities as if it were the absolute owner thereof (including, without limitation, the right to exchange at its discretion any and all of the Pledged Securities upon the merger, consolidation, reorganization, recapitalization or other fundamental change in the organizational structure of any Issuer, or upon the exercise by the Grantor or the Administrative Agent of any right, privilege or option pertaining to such Pledged Securities, and in connection therewith, the right to deposit and deliver any and all of the Pledged Securities with any committee, depositary, transfer agent, registrar or other designated agency upon such terms and conditions as the Administrative Agent may determine), all without liability except to account for property actually received by it, but the Administrative Agent shall have no duty to the Grantor to exercise any such right, privilege or option and shall not be responsible for any failure to do so or delay in so doing.

(c)           The Grantor hereby authorizes and instructs each Issuer of any Pledged Securities pledged by the Grantor hereunder (and each Issuer party hereto hereby agrees) to (i) comply with any instruction received by it from the Administrative Agent in writing that (x) states that an Event of Default has occurred and is continuing and (y) is otherwise in accordance with the terms of this Agreement, without any other or further instructions from the Grantor, and the Grantor agrees that each Issuer shall be fully protected in so complying, and (ii) unless otherwise expressly permitted hereby, pay any dividends or other payments with respect to the Pledged Securities directly to the Administrative Agent.

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(d)           After the occurrence and during the continuation of an Event of Default, if the Issuer of any Pledged Securities is the subject of bankruptcy, insolvency, receivership, custodianship or other proceedings under the supervision of any Governmental Authority, then all rights of the Grantor in respect thereof to exercise the voting and other consensual rights which the Grantor would otherwise be entitled to exercise with respect to the Pledged Securities issued by such Issuer shall cease, and all such rights shall thereupon become vested in the Administrative Agent who shall thereupon have the sole right to exercise such voting and other consensual rights, but the Administrative Agent shall have no duty to exercise any such voting or other consensual rights and shall not be responsible for any failure to do so or delay in so doing.

Section 7.02          Collections on Accounts, Etc.  The Administrative Agent hereby authorizes the Grantor to collect upon the Accounts, Instruments, Chattel Paper and Payment Intangibles, and the Administrative Agent may curtail or terminate said authority at any time after the occurrence and during the continuance of an Event of Default.  Upon the request of the Administrative Agent at any time after the occurrence and during the continuance of an Event of Default, the Grantor shall notify the Account Debtors that the applicable Accounts, Chattel Paper and Payment Intangibles have been assigned to the Administrative Agent for the ratable benefit of the Secured Parties and that payments in respect thereof shall be made directly to the Administrative Agent.  The Administrative Agent may, upon the occurrence and during the continuance of an Event of Default, in its own name or in the name of others communicate with the Account Debtors to verify with them to its satisfaction the existence, amount and terms of any Accounts, Chattel Paper or Payment Intangibles.

Section 7.03          Proceeds.  If required by the Administrative Agent at any time after the occurrence and during the continuance of an Event of Default, any payments of Accounts, Instruments, Chattel Paper and Payment Intangibles, when collected or received by the Grantor, and any other cash or non-cash Proceeds received by the Grantor upon the sale or other disposition of any Collateral, shall be forthwith (and, in any event, within two Business Days from the date of sale or other disposition of such Collateral) deposited by the Grantor in the exact form received, duly indorsed by the Grantor to the Administrative Agent if required, in a special collateral account maintained by the Administrative Agent, subject to withdrawal by the Administrative Agent for the ratable benefit of the Secured Parties only, as hereinafter provided, and, until so turned over, shall be held by the Grantor in trust for the Administrative Agent for the ratable benefit of the Secured Parties, segregated from other funds of the Grantor.  Each deposit of any such Proceeds shall be accompanied by a report identifying in reasonable detail the nature and source of the payments included in the deposit.  All Proceeds (including, without limitation, Proceeds constituting collections of Accounts, Chattel Paper, Instruments) while held by the Administrative Agent (or by the Grantor in trust for the Administrative Agent for the ratable benefit of the Secured Parties) shall continue to be collateral security for all of the Obligations and shall not constitute payment thereof until applied as hereinafter provided.  At such intervals as may be agreed upon by the Grantor and the Administrative Agent, or, if an Event of Default shall have occurred and be continuing, at any time at the Administrative Agent’s election, the Administrative Agent shall apply all or any part of the funds on deposit in said special collateral account on account of the Obligations in such order as the Administrative Agent may elect, and any part of such funds which the Administrative Agent elects not so to apply and deems not required as collateral security for the Obligations shall be paid over from

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time to time by the Administrative Agent to the Grantor or to whomsoever may be lawfully entitled to receive the same.

Section 7.04          UCC and Other Remedies.

(a)           If an Event of Default shall occur and be continuing, the Administrative Agent, on behalf of the Secured Parties, may exercise in its discretion, in addition to all other rights, remedies, powers and privileges granted to them in this Agreement, the other Loan Documents, any Permitted Swap Agreement and in any other instrument or agreement securing, evidencing or relating to the Obligations, all rights, remedies, powers and privileges of a secured party under the UCC (whether the UCC is in effect in the jurisdiction where such rights, remedies, powers or privileges are asserted) or any other applicable law or otherwise available at law or equity.  Without limiting the generality of the foregoing, the Administrative Agent, without demand of performance or other demand, presentment, protest, advertisement or notice of any kind (except any notice required by law referred to below) to or upon the Grantor or any other Person (all and each of which demands, defenses, advertisements and notices are hereby waived), may in such circumstances forthwith collect, receive, appropriate and realize upon the Collateral, or any part thereof, and/or may forthwith sell, lease, assign, give option or options to purchase, or otherwise dispose of and deliver the Collateral or any part thereof (or contract to do any of the foregoing), in one or more parcels at public or private sale or sales, at any exchange, broker’s board or office of the Administrative Agent or any other Secured Party or elsewhere upon such terms and conditions as it may deem advisable and at such prices as it may deem best, for cash or on credit or for future delivery without assumption of any credit risk.  The Administrative Agent or any other Secured Party shall have the right upon any such public sale or sales, and, to the extent permitted by law, upon any such private sale or sales, to purchase the whole or any part of the Collateral so sold, free of any right or equity of redemption in the Grantor, which right or equity is hereby waived and released.  If an Event of Default shall occur and be continuing, the Grantor further agrees, at the Administrative Agent’s request, to assemble the Collateral and make it available to the Administrative Agent at places which the Administrative Agent shall reasonably select, whether at the Grantor’s premises or elsewhere.  Any such sale or transfer by the Administrative Agent either to itself or to any other Person shall be absolutely free from any claim of right by the Grantor, including any equity or right of redemption, stay or appraisal which the Grantor has or may have under any rule of law, regulation or statute now existing or hereafter adopted.  Upon any such sale or transfer, the Administrative Agent shall have the right to deliver, assign and transfer to the purchaser or transferee thereof the Collateral so sold or transferred.  The Administrative Agent shall apply the net proceeds of any action taken by it pursuant to this Section 7.04, after deducting all reasonable costs and expenses of every kind incurred in connection therewith or incidental to the care or safekeeping of any of the Collateral or in any way relating to the Collateral or the rights of the Administrative Agent and the other Secured Parties hereunder, including, without limitation, reasonable attorneys’ fees and disbursements, to the payment in whole or in part of the Obligations, in accordance with Section 10.02 of the Credit Agreement, and only after such application and after the payment by the Administrative Agent of any other amount required by any provision of law, including, without limitation, Section 9.615 of the UCC, need the Administrative Agent account for the surplus, if any, to the Grantor.  To the extent permitted by applicable law, the Grantor waives all claims, damages and demands it may acquire against the Administrative Agent or any other Secured Party arising out of the exercise by them of any rights

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hereunder.  If any notice of a proposed sale or other disposition of Collateral shall be required by law, such notice shall be deemed reasonable and proper if given at least 10 days before such sale or other disposition.

(b)           In the event that the Administrative Agent elects not to sell the Collateral, the Administrative Agent retains its rights to dispose of or utilize the Collateral or any part or parts thereof in any manner authorized or permitted by law or in equity, and to apply the proceeds of the same towards payment of the Obligations.  Each and every method of disposition of the Collateral described in this Agreement shall constitute disposition in a commercially reasonable manner.  The Administrative Agent may appoint any Person as agent to perform any act or acts necessary or incident to any sale or transfer of the Collateral.

Section 7.05          Private Sales of Pledged Securities.  The Grantor recognizes that the Administrative Agent may be unable to effect a public sale of any or all the Pledged Securities, by reason of certain prohibitions contained in the Securities Act and applicable state securities laws or otherwise, and may be compelled to resort to one or more private sales thereof to a restricted group of purchasers which will be obliged to agree, among other things, to acquire such securities for their own account for investment and not with a view to the distribution or resale thereof.  The Grantor acknowledges and agrees that any such private sale may result in prices and other terms less favorable than if such sale were a public sale and, notwithstanding such circumstances, agrees that any such private sale shall be deemed to have been made in a commercially reasonable manner.  The Administrative Agent shall be under no obligation to delay a sale of any of the Pledged Securities for the period of time necessary to permit the Issuer thereof to register such securities for public sale under the Securities Act, or under applicable state securities laws, even if such Issuer would agree to do so.  The Grantor agrees to use its best efforts to do or cause to be done all such other acts as may reasonably be necessary to make such sale or sales of all or any portion of the Pledged Securities pursuant to this Section 7.05 valid and binding and in compliance with any and all other applicable Governmental Requirements.  The Grantor further agrees that a breach of any of the covenants contained in this Section 7.05 will cause irreparable injury to the Administrative Agent and the other Secured Parties, that the Administrative Agent and the other Secured Parties have no adequate remedy at law in respect of such breach and, as a consequence, that each and every covenant contained in this Section 7.05 shall be specifically enforceable against the Grantor, and the Grantor hereby waives and agrees not to assert any defenses against an action for specific performance of such covenants.  Waiver; Deficiency.  The Grantor waives and agrees not to assert any rights or privileges which it may acquire under the UCC or any other applicable law.  The Grantor shall remain liable for any deficiency if the proceeds of any sale or other disposition of the Collateral are insufficient to pay its Obligations and the fees and disbursements of any attorneys employed by the Administrative Agent or any other Secured Party to collect such deficiency.

Section 7.07          Non-Judicial Enforcement.  The Administrative Agent may enforce its rights hereunder without prior judicial process or judicial hearing, and to the extent permitted by law, the Grantor expressly waives any and all legal rights which might otherwise require the Administrative Agent to enforce its rights by judicial process.

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ARTICLE VIII
The Administrative Agent

Section 8.01          Administrative Agent’s Appointment as Attorney-in-Fact, Etc.

(a)           The Grantor hereby irrevocably constitutes and appoints the Administrative Agent and any officer or agent thereof, with full power of substitution, as its true and lawful attorney-in-fact with full irrevocable power and authority in the place and stead of the Grantor and in the name of the Grantor or in its own name, for the purpose of carrying out the terms of this Agreement, to take any and all reasonably appropriate action and to execute any and all documents and instruments which may be reasonably necessary or desirable to accomplish the purposes of this Agreement, and, without limiting the generality of the foregoing, the Grantor hereby gives the Administrative Agent the power and right, on behalf of the Grantor, without notice to or assent by the Grantor, to do any or all of the following:

(i)            pay or discharge taxes and Liens levied or placed on or threatened against the Collateral, effect any repairs or any insurance called for by the terms of this Agreement and pay all or any part of the premiums therefor and the costs thereof;

(ii)           execute, in connection with any sale provided for in Section 7.04 or Section 7.05, any endorsements, assignments or other instruments of conveyance or transfer with respect to the Collateral; and

(iii)          (A) direct any party liable for any payment under any of the Collateral to make payment of any and all moneys due or to become due thereunder directly to the Administrative Agent or as the Administrative Agent shall direct; (B) take possession of and indorse and collect any checks, drafts, notes, acceptances or other instruments for the payment of moneys due under any Account, Instrument, General Intangible, Chattel Paper or Payment Intangible or with respect to any other Collateral, and to file any claim or to take any other action or proceeding in any court of law or equity or otherwise deemed appropriate by the Administrative Agent for the purpose of collecting any all such moneys due under any Account, Instrument or  General Intangible or with respect to any other Collateral whenever payable; (C) ask or demand for, collect, and receive payment of and receipt for, any and all moneys, claims and other amounts due or to become due at any time in respect of or arising out of any Collateral; (D) sign and indorse any invoices, freight or express bills, bills of lading, storage or warehouse receipts, drafts against debtors, assignments, verifications, notices and other documents in connection with any of the Collateral; (E) receive, change the address for delivery, open and dispose of mail addressed to the Grantor, and to execute, assign and indorse negotiable and other instruments for the payment of money, documents of title or other evidences of payment, shipment or storage for any form of Collateral on behalf of and in the name of the Grantor; (F) commence and prosecute any suits, actions or proceedings at law or in equity in any court of competent jurisdiction to collect the Collateral or any portion thereof and to enforce any other right in respect of any Collateral; (G) defend any suit, action or proceeding brought against the Grantor with respect to any Collateral; (H) settle, compromise or adjust any such suit, action or proceeding and, in connection therewith, give such discharges or releases as the Administrative Agent may deem appropriate; and (I) generally, sell, transfer, pledge and make any agreement with respect to or otherwise deal with any of the Collateral as fully and completely as though the Administrative Agent were the absolute owner thereof for all purposes, and do, at the Administrative Agent’s option and the Grantor’s expense, at any time, or from time to time, all acts and things which the Administrative Agent deems necessary to protect, preserve or realize

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upon the Collateral and the Administrative Agent’s and the other Secured Parties’ security interests therein and to effect the intent of this Agreement, all as fully and effectively as the Grantor might do.

Anything in this Section 8.01(a) to the contrary notwithstanding, the Administrative Agent agrees that it will not exercise any rights under the power of attorney provided for in this Section 8.01(a) unless an Event of Default shall have occurred and be continuing.

(b)           If the Grantor fails to perform or comply with any of its agreements contained herein within the applicable grace periods, the Administrative Agent, at its option, but without any obligation so to do, may perform or comply, or otherwise cause performance or compliance, with such agreement.

(c)           The expenses of the Administrative Agent incurred in connection with actions undertaken as provided in this Section 8.01, together with interest thereon at the Post-Default Rate from the date of payment by the Administrative Agent to the date reimbursed by the Grantor, shall be payable by the Grantor to the Administrative Agent on demand.

(d)           The Grantor hereby ratifies all that said attorneys shall lawfully do or cause to be done by virtue and in compliance hereof.  All powers, authorizations and agencies contained in this Agreement are coupled with an interest and are irrevocable until this Agreement is terminated and the security interests created hereby are released.

Section 8.02          Duty of Administrative Agent.  The Administrative Agent’s sole duty with respect to the custody, safekeeping and physical preservation of the Collateral in its possession, under Section 9.207 of the UCC or otherwise, shall be to deal with it in the same manner as the Administrative Agent deals with similar property for its own account and shall be deemed to have exercised reasonable care in the custody and preservation of the Collateral in its possession if the Collateral is accorded treatment substantially equal to that which comparable secured parties accord comparable collateral.  Neither the Administrative Agent, any other Secured Party nor any of their respective officers, directors, employees or agents shall be liable for failure to demand, collect or realize upon any of the Collateral or for any delay in doing so or shall be under any obligation to sell or otherwise dispose of any Collateral upon the request of the Grantor or any other Person or to take any other action whatsoever with regard to the Collateral or any part thereof.  The powers conferred on the Administrative Agent and the other Secured Parties hereunder are solely to protect the Administrative Agent’s and the other Secured Parties’ interests in the Collateral and shall not impose any duty upon the Administrative Agent or any other Secured Party to exercise any such powers.  The Administrative Agent and the other Secured Parties shall be accountable only for amounts that they actually receive as a result of the exercise of such powers, and neither they nor any of their officers, directors, employees or agents shall be responsible to the Grantor for any act or failure to act hereunder, except for their own gross negligence or willful misconduct.  To the fullest extent permitted by applicable law, the Administrative Agent shall be under no duty whatsoever to make or give any presentment, notice of dishonor, protest, demand for performance, notice of non-performance, notice of intent to accelerate, notice of acceleration, or other notice or demand in connection with any Collateral or the Obligations, or to take any steps necessary to preserve any rights against the Grantor or other Person or ascertaining or taking action with respect to calls, conversions, exchanges, maturities,

24

tenders or other matters relative to any Collateral, whether or not it has or is deemed to have knowledge of such matters.  The Grantor, to the extent permitted by applicable law, waives any right of marshaling in respect of any and all Collateral, and waives any right to require the Administrative Agent or any other Secured Party to proceed against the Grantor or other Person, exhaust any Collateral or enforce any other remedy which the Administrative Agent or any other Secured Party now has or may hereafter have against the Grantor or other Person.

Section 8.03          Execution of Financing Statements.  Pursuant to the UCC and any other applicable law, the Grantor authorizes the Administrative Agent, its counsel or its representative, at any time and from time to time, to file or record financing statements, continuation statements, amendments thereto and other filing or recording documents or instruments with respect to the Collateral without the signature of the Grantor in such form and in such offices as the Administrative Agent reasonably determines appropriate to perfect the security interests of the Administrative Agent under this Agreement.  Additionally, the Grantor authorizes the Administrative Agent, its counsel or its representative, at any time and from time to time, to file or record such financing statements that describe the collateral covered thereby as “all assets of the Grantor”, “all personal property of the Grantor” or words of similar effect.  A photographic or other reproduction of this Agreement shall be sufficient as a financing statement or other filing or recording document or instrument for filing or recording in any jurisdiction.

Section 8.04          Authority of Administrative Agent.  The Grantor acknowledges that the rights and responsibilities of the Administrative Agent under this Agreement with respect to any action taken by the Administrative Agent or the exercise or non-exercise by the Administrative Agent of any option, voting right, request, judgment or other right or remedy provided for herein or resulting or arising out of this Agreement shall, as between the Administrative Agent and the other Secured Parties, be governed by the Credit Agreement and by such other agreements with respect thereto as may exist from time to time among them, but, as between the Administrative Agent and the Grantor, the Administrative Agent shall be conclusively presumed to be acting as agent for the Secured Parties with full and valid authority so to act or refrain from acting, and the Grantor shall not be under any obligation, or entitlement, to make any inquiry respecting such authority.

ARTICLE IX
Subordination of Indebtedness

Section 9.01          Subordination of All Guarantor Claims.  As used herein, the term “Guarantor Claims” shall mean all debts and obligations of the Borrower to the Grantor, whether such debts and obligations now exist or are hereafter incurred or arise, or whether the obligation of the debtor thereon be direct, contingent, primary, secondary, several, joint and several, or otherwise, and irrespective of whether such debts or obligations be evidenced by note, contract, open account, or otherwise, and irrespective of the Person or Persons in whose favor such debts or obligations may, at their inception, have been, or may hereafter be created, or the manner in which they have been or may hereafter be acquired by. After and during the continuation of an Event of Default, no Grantor shall receive or collect, directly or indirectly, from any obligor in respect thereof any amount upon the Guarantor Claims.

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Section 9.02          Claims in Bankruptcy.  In the event of receivership, bankruptcy, reorganization, arrangement, debtor’s relief or other insolvency proceedings involving the Grantor, the Administrative Agent on behalf of the Secured Parties shall have the right to prove their claim in any proceeding, so as to establish their rights hereunder and receive directly from the receiver, trustee or other court custodian, dividends and payments which would otherwise be payable upon Guarantor Claims.  The Grantor hereby assigns such dividends and payments to the Administrative Agent for the benefit of the Secured Parties for application against the Obligations as provided under Section 10.02 of the Credit Agreement.  Should the Administrative Agent or any other Secured Party receive, for application upon the Obligations, any such dividend or payment which is otherwise payable to the Grantor, and which shall constitute a credit upon the Guarantor Claims, then upon payment in full of the Obligations, the intended recipient shall become subrogated to the rights of the Administrative Agent and the other Secured Parties to the extent that such payments to the Administrative Agent and the other Secured Parties on the Guarantor Claims have contributed toward the liquidation of the Obligations, and such subrogation shall be with respect to that proportion of the Obligations which would have been unpaid if the Administrative Agent and the other Secured Parties had not received dividends or payments upon the Guarantor Claims.

Section 9.03          Payments Held in Trust.  In the event that notwithstanding Section 9.01 and Section 9.02, the Grantor should receive any funds, payments, claims or distributions which is prohibited by such Sections, then it agrees: (a) to hold in trust for the Administrative Agent and the other Secured Parties an amount equal to the amount of all funds, payments, claims or distributions so received, and (b) that it shall have absolutely no dominion over the amount of such funds, payments, claims or distributions except to pay them promptly to the Administrative Agent, for the benefit of the Secured Parties; and the Grantor covenants promptly to pay the same to the Administrative Agent.

Section 9.04          Liens Subordinate.  The Grantor agrees that, until Security Termination has occurred, any Liens securing payment of the Guarantor Claims shall be and remain inferior and subordinate to any Liens securing payment of the Obligations, regardless of whether such encumbrances in favor of the Grantor, the Administrative Agent or any other Secured Party presently exist or are hereafter created or attach.  Until Security Termination has occurred, without the prior written consent of the Administrative Agent, the Grantor shall not (a) exercise or enforce any creditor’s right it may have against any debtor in respect of the Guarantor Claims, or (b) foreclose, repossess, sequester or otherwise take steps or institute any action or proceeding (judicial or otherwise, including without limitation the commencement of or joinder in any liquidation, bankruptcy, rearrangement, debtor’s relief or insolvency proceeding) to enforce any Lien held by it.

Section 9.05          Notation of Records.  Upon the request of the Administrative Agent, all promissory notes and all accounts receivable ledgers or other evidence of the Guarantor Claims accepted by or held by the Grantor shall contain a specific written notice thereon that the indebtedness evidenced thereby is subordinated under the terms of this Agreement.

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ARTICLE X
Miscellaneous

Section 10.01       Waiver.  No failure on the part of the Administrative Agent or any other Secured Party to exercise and no delay in exercising, and no course of dealing with respect to, any right, remedy, 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, remedy, power or privilege.  The rights, remedies, powers and privileges provided herein are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.  The exercise by the Administrative Agent of any one or more of the rights, powers and remedies herein shall not be construed as a waiver of any other rights, powers and remedies, including, without limitation, any rights of set-off.

Section 10.02       Notices.  All notices and other communications provided for herein shall be given in the manner and subject to the terms of Section 12.01 of the Credit Agreement; provided that any such notice, request or demand to or upon the New Guarantor shall be addressed to the New Guarantor at its notice address set forth on Schedule 1.

Section 10.03       Payment of Expenses, Indemnities, Etc.

(a)           The Grantor agrees to pay or promptly reimburse the Administrative Agent and each other Secured Party for all advances, charges, costs and expenses (including, without limitation, all costs and expenses of holding, preparing for sale and selling, collecting or otherwise realizing upon the Collateral and all attorneys’ fees, legal expenses and court costs) incurred by any Secured Party in connection with the exercise of its respective rights and remedies hereunder, including, without limitation, any advances, charges, costs and expenses that may be incurred in any effort to enforce any of the provisions of this Agreement or any obligation of the Grantor in respect of the Collateral or in connection with (i) the preservation of the Lien of, or the rights of, the Administrative Agent or any other Secured Party under this Agreement, (ii) any actual or attempted sale, lease, disposition, exchange, collection, compromise, settlement or other realization in respect of, or care of, the Collateral, including all such costs and expenses incurred in any bankruptcy, reorganization, workout or other similar proceeding, or (iii) collecting against the Grantor under the guarantee contained in Article II or otherwise enforcing or preserving any rights under this Agreement and the other Loan Documents to which the Grantor is a party.

(b)           The Grantor agrees to indemnify and pay, and to save the Administrative Agent and the other Secured Parties harmless from, any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever (including, without limitation, court costs and attorneys’ fees, any and all liabilities with respect to, or resulting from any delay in paying, any and all stamp, excise, sales or other taxes which may be payable or determined to be payable with respect to any of the Collateral or in connection with any of the transactions contemplated by this Agreement) incurred because of, incident to, or with respect to, the Collateral (including, without limitation, any exercise of rights or remedies in connection therewith) or the execution, delivery, enforcement, performance and administration of this Agreement, to the extent the Borrower would be required to do so pursuant to Section 12.03 of the Credit Agreement; and THE INDEMNITY PROVIDED HEREIN EXTEND TO EACH PERSON BEING INDEMNIFIED NOTWITHSTANDING THE SOLE OR CONCURRENT NEGLIGENCE

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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 PERSONS BEING INDEMNIFIED OR BY REASON OF STRICT LIABILITY IMPOSED WITHOUT FAULT ON ANY ONE OR MORE OF THE PERSONS BEING INDEMNIFIED; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY PERSON BEING INDEMNIFIED, BE AVAILABLE TO THE EXTENT THAT (I) SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED EXPENSES ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO HAVE RESULTED FROM THE GROSS NEGLIGENCE, BAD FAITH OR WILFUL MISCONDUCT OF SUCH PERSON BEING INDEMNIFIED OR (II) SUCH CLAIMS (OTHER THAN CLAIMS AGAINST THE ADMINISTRATIVE AGENT, THE ARRANGER OR THE ISSUING BANK) ARE SOLELY BETWEEN PERSONS BEING INDEMNIFIED.  All amounts for which the Grantor is liable pursuant to this Section 10.03 shall be due and payable by the Grantor to the Secured Parties upon demand.

Section 10.04       Amendments in Writing.  None of the terms or provisions of this Agreement may be waived, amended, supplemented or otherwise modified except in accordance with Section 12.02 of the Credit Agreement.

Section 10.05       Successors and Assigns.  This Agreement shall be binding upon the successors and assigns of the Grantor and shall inure to the benefit of the Administrative Agent and the other Secured Parties and their successors and permitted assigns; provided that, the Grantor may not assign, transfer or delegate any of its rights or obligations under this Agreement without the prior written consent of the Administrative Agent and the Lenders, except as otherwise permitted under the Credit Agreement.

Section 10.06       Invalidity.  In the event that any one or more of the provisions contained in this Agreement or in any of the Loan Documents to which the Grantor is a party 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 or such other Loan Document.

Section 10.07       Counterparts.  This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument and any of the parties hereto may execute this Agreement by signing any such counterpart.

Section 10.08       Survival.  The obligations of the parties under Section 10.03 shall survive the repayment of the Loans and the termination of the Letters of Credit, Permitted Swap Agreements, Credit Agreement and Commitments.  To the extent that any payments on the Obligations 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 Obligations so satisfied shall be revived and continue as if such payment or proceeds had not been received and the Administrative Agent’s and the other Secured Parties’ Liens, security

28

interests, rights, powers and remedies under this Agreement and each Security Instrument shall continue in full force and effect.  In such event, each Security Instrument shall be automatically reinstated and the Grantor shall take such action as may be reasonably requested by the Administrative Agent and the other Secured Parties to effect such reinstatement.

Section 10.09       Captions.  Captions and section headings appearing herein are included solely for convenience of reference and are not intended to affect the interpretation of any provision of this Agreement.

Section 10.10       Governing Law; Submission to Jurisdiction.

(a)           THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

(b)           ANY LEGAL ACTION OR PROCEEDING WITH RESPECT TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENTS TO WHICH THE GRANTOR IS A PARTY 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 EACH OF THE LENDERS, THE ADMINISTRATIVE AGENT AND THE GRANTOR 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 OF THE LENDERS, THE ADMINISTRATIVE AGENT AND THE GRANTOR 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.  THIS SUBMISSION TO JURISDICTION IS NON-EXCLUSIVE AND DOES NOT PRECLUDE THE ADMINISTRATIVE AGENT OR ANY LENDER FROM OBTAINING JURISDICTION OVER SUCH GRANTOR IN ANY COURT OTHERWISE HAVING JURISDICTION.

(c)           EACH OF THE LENDERS, THE ADMINISTRATIVE AGENT AND THE GRANTOR 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 SUCH PERSON AT THE ADDRESS SPECIFIED ON ITS SIGNATURE PAGE OF THIS AGREEMENT OR THE CREDIT AGREEMENT, AS APPLICABLE, SUCH SERVICE TO BECOME EFFECTIVE THIRTY (30) DAYS AFTER SUCH MAILING.  NOTHING HEREIN SHALL AFFECT THE RIGHT OF THE ADMINISTRATIVE AGENT OR ANY LENDER OR ANY HOLDER OF A NOTE OR THE GRANTOR TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO COMMENCE LEGAL PROCEEDINGS OR OTHERWISE PROCEED AGAINST THE GRANTOR IN ANY OTHER JURISDICTION.

(d)           THE ADMINISTRATIVE AGENT, THE GRANTOR AND EACH LENDER HEREBY (I) IRREVOCABLY AND UNCONDITIONALLY WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, TRIAL BY JURY IN ANY LEGAL ACTION OR

29

PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN; (II) IRREVOCABLY WAIVE, 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; (III) CERTIFY 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) ACKNOWLEDGE 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 10.10.

Section 10.11       Acknowledgments.

(a)           The Grantor hereby acknowledges that:

(i)            it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents to which it is a party;

(ii)           neither the Administrative Agent nor any other Secured Party has any fiduciary relationship with or duty to the Grantor arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between the Grantor, on the one hand, and the Administrative Agent and the other Secured Parties, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

(iii)          no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Secured Parties or among the Grantor and the Lenders.

(b)           Each of the parties hereto specifically agrees that it has a duty to read this Agreement and the Security Instruments and agrees that it is charged with notice and knowledge of the terms of this Agreement and the other Security Instruments; 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 Security Instruments; and has received the advice of its attorney in entering into this Agreement and the other Security Instruments; and that it recognizes that certain of the terms of this Agreement and the other Security Instruments 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 Security Instruments on the basis that the party had no notice or knowledge of such provision or that the provision is not “conspicuous.”

(c)           The Grantor warrants and agrees that each of the waivers and consents set forth in this Agreement are made voluntarily and unconditionally after consultation with outside

30

legal counsel and with full knowledge of their significance and consequences, with the understanding that events giving rise to any defense or right waived may diminish, destroy or otherwise adversely affect rights which the Grantor otherwise may have against the Borrower, any other Existing Grantor, the Secured Parties or any other Person or against any collateral.  If, notwithstanding the intent of the parties that the terms of this Agreement shall control in any and all circumstances, any such waivers or consents are determined to be unenforceable under applicable law, such waivers and consents shall be effective to the maximum extent permitted by law.

Section 10.12       Set-Off.  The Grantor agrees that, in addition to (and without limitation of) any right of set-off, bankers’ lien or counterclaim a Secured Party may otherwise have, each Secured Party shall have the right and be entitled (after consultation with the Administrative Agent), at its option, to offset (i) balances held by it or by any of its Affiliates for account of the Grantor or any Subsidiary at any of its offices, in Dollars or in any other currency, and (ii) amounts due and payable to such Lender (or any Affiliate of such Lender) under any Permitted Swap Agreement, against any principal of or interest on any of such Secured Party’s Loans, or any other amount due and payable to such Secured Party hereunder, which is not paid when due (regardless of whether such balances are then due to such Person), in which case it shall promptly notify the Borrower and the Administrative Agent thereof, provided that such Secured Party’s failure to give such notice shall not affect the validity thereof.

Section 10.13       Releases.

(a)           Release Upon Payment in Full.  The grant of a security interest hereunder and all of rights, powers and remedies in connection herewith shall remain in full force and effect until the Administrative Agent has (i) retransferred and delivered all Collateral in its possession to the Grantor, and (ii) executed a written release or termination statement and reassigned to the Grantor without recourse or warranty any remaining Collateral and all rights conveyed hereby.  Upon the occurrence of Security Termination, the Administrative Agent, at the written request and expense of the Borrower, will promptly release, reassign and transfer the Collateral to the Grantor and declare this Agreement to be of no further force or effect.

(b)           Further Assurances.  If any of the Collateral shall be sold, transferred or otherwise disposed of by the Grantor in a transaction permitted by the Credit Agreement, then the Administrative Agent, at the request and sole expense of the Grantor, shall promptly execute and deliver to the Grantor all releases or other documents necessary or reasonably desirable for the release of the Liens created hereby on such Collateral and the capital stock of the Grantor.  At the request and sole expense of the Borrower, the Grantor shall be released from its obligations hereunder in the event that all the capital stock of the Grantor shall be sold, transferred or otherwise disposed of in a transaction permitted by the Credit Agreement; provided that the Borrower shall have delivered to the Administrative Agent, at least ten Business Days prior to the date of the proposed release, a written request for release identifying the terms of the sale or other disposition in reasonable detail, including the price thereof and any expenses in connection therewith, together with a certification by the Borrower stating that such transaction is in compliance with the Credit Agreement and the other Loan Documents.

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(c)           Retention in Satisfaction.  Except as may be expressly applicable pursuant to Section 9.620 of the UCC, no action taken or omission to act by the Administrative Agent or the other Secured Parties hereunder, including, without limitation, any exercise of voting or consensual rights or any other action taken or inaction, shall be deemed to constitute a retention of the Collateral in satisfaction of the Obligations or otherwise to be in full satisfaction of the Obligations, and the Obligations shall remain in full force and effect, until the Administrative Agent and the other Secured Parties shall have applied payments (including, without limitation, collections from Collateral) towards the Obligations in the full amount then outstanding or until such subsequent time as is provided in Section 10.13(a).

Section 10.14       Reinstatement.  The obligations of the Grantor under this Agreement (including, without limitation, with respect to the guarantee contained in Article II and the provision of collateral herein) shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Obligations is rescinded or must otherwise be restored or returned by the Administrative Agent or any other Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower or the Grantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or the Grantor or any substantial part of its property, or otherwise, all as though such payments had not been made.

Section 10.15       Acceptance.  The Grantor hereby expressly waives notice of acceptance of this Agreement, acceptance on the part of the Administrative Agent and the other Secured Parties being conclusively presumed by their request for this Agreement and delivery of the same to the Administrative Agent.

Section 10.16       No Oral Agreements.  THE LOAN DOCUMENTS (OTHER THAN THE LETTERS OF CREDIT ISSUED UNDER THE CREDIT AGREEMENT) EMBODY THE ENTIRE AGREEMENT AND UNDERSTANDING BETWEEN THE PARTIES AND SUPERSEDE ALL OTHER AGREEMENTS AND UNDERSTANDINGS BETWEEN SUCH PARTIES RELATING TO THE SUBJECT MATTER HEREOF AND THEREOF.  THE LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES 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 HERETO.

[Signature Page to Follow]

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IN WITNESS WHEREOF, each of the undersigned has caused this Guarantee and Collateral Agreement to be duly executed and delivered as of the date first above written.

NEW GUARANTOR:	JONES ENERGY, INC.
	By:	/s/ Robert J. Brooks
		Robert J. Brooks
		Executive Vice President,
		Chief Financial Officer, Secretary, and
		Treasurer

Signature Page to

Guarantee and Collateral Agreement

(Jones Energy, Inc.)

	Acknowledged and Agreed to as
	of the date hereof by:
ADMINISTRATIVE AGENT:	WELLS FARGO BANK, N.A.
	By:	/s/ Paul Squires
		Paul Squires
		Managing Director

Signature Page to

Guarantee and Collateral Agreement

(Jones Energy, Inc.)

Schedule 1

NOTICE ADDRESSES OF GRANTOR

c/o Jones Energy Holdings, LLC

Notice Address:

Attn:  Robert J. Brooks

807 Las Cimas Parkway

Suite 350

Austin, TX 78746

Telephone: 512-672-7170

Facsimile: 512-328-5394

Schedule 1 - 1

Schedule 2

COMMERCIAL TORT CLAIMS

None.

Schedule 2 - 1

Schedule 3

FILINGS AND OTHER ACTIONS
REQUIRED TO PERFECT SECURITY INTERESTS

Uniform Commercial Code Filings

Debtor	Filing Type	Jurisdiction
Jones Energy, Inc.	UCC-1	Delaware

Schedule 3 - 1

Schedule 4

CORRECT LEGAL NAME, LOCATION OF JURISDICTION OF ORGANIZATION, ORGANIZATIONAL IDENTIFICATION NUMBER, TAXPAYER IDENTIFICATION NUMBER AND CHIEF EXECUTIVE OFFICE

Correct Legal Name:	Jones Energy, Inc.
Location of jurisdiction of organization:	Delaware
Organizational identification number:	5301435
Chief Executive Office	807 Las Cimas Parkway Suite 350 Austin, TX 78746
Taxpayer identification number:	80-0907968

Schedule 4 - 1

Schedule 5

PRIOR NAMES

None.

Schedule 5 - 1

EX-21.1

Exhibit 21.1

Subsidiaries

Entity	State of Formation
Jones Energy Holdings, LLC	Delaware
CCPR Sub LLC	Delaware
Nosley Assets, LLC	Delaware
Jones Energy, LLC	Texas
JRJ Opco, LLC	Texas

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-190471) of Jones Energy, Inc. of our report dated March 14, 2014 relating to the consolidated financial statements, which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 14, 2014

EX-23.2

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, 2013 (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, 2011, 2012 and 2013 for Jones Energy Holdings, LLC.  In addition, we hereby consent to the inclusion of our summary report dated February 4, 2014 as an exhibit to the Annual Report.  We further consent to the incorporation by reference thereof into the Company’s Registration Statement on Form S-8 (File No. 333-190471).

/s/ W. Todd Brooker

W. Todd Brooker, P.E.

Vice-President

Cawley Gillespie & Associates, Inc.

Texas Registered Engineering Firm F-693.

Austin, Texas

March 14, 2014

EX-31.1

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 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)) 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)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

c)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.

5.The registrant’s other certifying officer 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 14, 2014

EX-31.2

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 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)) 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)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

c)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.

5.The registrant’s other certifying officer 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 14, 2014

EX-32.1

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, 2013, 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 14, 2014

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.

EX-32.2

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, 2013, 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 14, 2014

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.

EX-99.1

Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1107	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www.cgaus.com

February 4, 2014

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, 2013
	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 February 4, 2014 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, 2013, 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	Proved*
		Developed	Developed	Proved	Total	Proved
		Producing	Non-Producing	Undeveloped	Proved	Developed
Net Reserves
Oil	- Mbbl	6,068.2	1,061.0	9,559.1	16,688.3	7,129.2
Gas	- MMcf	127,450.2	12,172.3	97,025.1	236,647.5	139,622.5
NGL	- Mbbl	17,645.1	1,456.1	13,814.2	32,915.5	19,101.3
BOE	- Mbbl	44,955.0	4,545.8	39,544.2	89,045.1	49,500.9
Revenue
Oil	- M$	557,999.4	96,791.1	876,131.1	1,530,922.3	654,790.4
Gas	- M$	402,092.2	37,590.0	300,553.8	740,235.8	439,682.3
NGL	- M$	476,266.5	41,621.5	414,650.4	932,538.3	517,887.9
Other	- M$	2,742.5	0.0	7,278.8	10,021.4	2,742.5
Severance Taxes	- M$	84,837.6	9,336.0	75,209.6	169,383.2	94,173.7
Ad Valorem Taxes	- M$	20,054.9	3,329.1	22,823.5	46,207.5	23,384.0
Operating Expenses	- M$	250,557.1	14,526.1	163,045.0	428,128.4	265,083.1
Other Deductions	- M$	45,331.1	11,351.9	34,573.4	91,256.1	56,683.0
Investments	- M$	741.3	15,164.4	533,437.1	549,342.6	15,905.7
Net Operating Income	- M$	1,037,578.9	122,295.1	769,525.4	1,929,399.4	1,159,874.1
Discounted @ 10% (Present Worth)	- M$	605,541.2	80,086.0	331,844.9	1,017,472.1	685,627.3

* Proved Developed Non-Producing shown above also includes Proved Developed Shut-In properties.

Jones Energy Holdings, LLC Interests

February 4, 2014

Page 2

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 7,129.2 Mbbl oil, 139,622.5 MMcf gas and 19,101.3 Mbbl NGLs (or 49,500.9 MBOE). Of the Proved Developed reserves, 44,955.0 MBOE were attributed to producing zones in existing wells and 4,545.8 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, 2013 were $96.78/bbl and $3.67/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 (WSJ, Bloomberg) during 2013 and the base gas price is based upon Henry Hub spot prices (WSJ) during 2013.

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 31% of WTI-Cushing oil prices based upon data provided by JEH. The gas price differentials provided were based on the first month of the forward curve 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:

Jones Energy Holdings, LLC Interests

February 4, 2014

Page 3

	Panhandle		ANR Pipeline		Nat. Gas Pipeline Co.		Centerpoint		Northern Nat. Gas
	TX/OK		Company OK		of America Mid-Con.		East		Demarcation
Mo-Yr	(PEPL)		(ANR)		(NGPL)		(Centerpoint)		(DEMARC)
01-2014	-0.20		-0.13		-0.13		-0.13		0.01
Thereafter	0.0	%	0.0	%	0.0	%	0.0	%	0.0	%
Cap	-0.20		-0.13		-0.13		-0.13		0.01

After these pricing adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $91.736 per barrel for oil, $3.128 per MCF for gas and $28.331 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. 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 $0.223/MCF and the operating cost for the Cleveland Pipeline cases are 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 rates of 2.0% to 3.0% 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 1.0% of gas revenue (15% of standard rate) 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 1.095% of revenue were applied to horizontal wells for 48 months if drilled January 1, 2013 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 836 PDP properties for this report, including the Cleveland Pipeline System case, and 119 PDNP properties with start dates and investments as provided. The Cleveland Pipeline System was 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, 117 PDSI properties were included which require further review by JEH for potential upside or confirmation as P&A candidates.

This report also includes 377 proved drilling locations (328 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 reservoir contains 242 locations (236 commercial) plus one Cleveland Pipeline Case; the Granite Wash reservoir contains 6 locations (4 commercial); the Marmaton reservoir contains 26 locations (26 commercial); and the Woodford reservoir contains 103 locations (62 commercial). 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. JEH has requested Texas drilling permits on at least nine (9) occasions for a fifth horizontal Cleveland location and has not been denied, and has drilled eight (8) sections with five (5) horizontal Cleveland wells; therefore, some sections were given up to five (5) horizontal proved locations depending on

Jones Energy Holdings, LLC Interests

February 4, 2014

Page 4

well density and offsetting performance.  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 $2,015,000 for each of the 236 Cleveland wells, $2,191,000 for each of the 4 Granite Wash wells, $135,000 for each of the 26 Marmaton wells, and $734,000 for each of the 62 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. Non-commercial PDNP and/or PUD properties shown in Table II’s and individual cash flow tables do not meet SEC guidelines for commerciality and therefore are not booked as reserves. These non-commercial properties are included in this report for the sole purpose of tracking wellbores and/or drilling locations within JEH.

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 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.

Jones Energy Holdings, LLC Interests

February 4, 2014

Page 5

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 not been included as part of this evaluation.

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
/s/ W. Todd Brooker, P. E.
W. Todd Brooker, P. E.
Senior Vice President

XML

Fair Value Measurement (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011
Changes in fair value of Level 3 instruments
Balance at the beginning of the period	$ (1,519,000)	$ (2,083,000)
Purchases	(1,095,000)	(2,352,000)
Settlements	(210,000)
Transfer to Level 2	(753,000)	2,370,000
Transfers to Level 3		834,000
Changes in fair value	2,342,000	(288,000)
Balance at the end of the period	(1,235,000)	(1,519,000)	(2,083,000)
Offsetting Assets and Liabilities
Number of counterparties to commodity derivative contracts	6
Nonfinancial Assets and Liabilities
Impairment of proved properties	0	18,800,000	19,800,000
Impairment of unproved properties	14,400,000	0	12,200,000
Commodity derivative contracts
Assets
Gross Amounts of Recognized Assets / Liabilities	38,071,000	49,200,000
Gross Amounts Offset in the Balance Sheet	(6,035,000)	(7,831,000)
Net Amounts of Assets Presented in the Balance Sheet	32,036,000	41,369,000
Gross Amounts Not Offset in the Balance Sheet	2,199,000	1,478,000
Net Amount	34,235,000	42,847,000
Liabilities
Gross Amounts of Recognized Assets	(14,347,000)	(17,928,000)
Gross Amounts Offset in the Balance Sheet	6,035,000	7,831,000
Net Amounts of Assets Presented in the Balance Sheet	(8,312,000)	(10,097,000)
Gross Amounts Not Offset in the Balance Sheet	(2,542,000)	(1,595,000)
Net Amount	$ (10,854,000)	$ (11,692,000)

XML

Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Benefit Plans
Amount contributed to the Plan	$ 0.3	$ 0.2

XML

Significant Accounting Policies (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 5,430,000	$ 5,335,000
Less: Accumulated depreciation and amortization	(1,986,000)	(1,937,000)
Net other property, plant and equipment	3,444,000	3,398,000
Depreciation and amortization of other property, plant and equipment	800,000	800,000	700,000
Oil and Gas Sales Payable
Period of remittance for oil and gas sales payable	60 days
Asset Retirement Obligations
ARO liability at beginning of year	9,506,000	9,563,000
Liabilities incurred	1,516,000	662,000	4,077,000
Accretion of discount	608,000	596,000
Liabilities settled due to sale of related properties	(271,000)	(927,000)
Liabilities settled due to plugging and abandonment	(702,000)	(388,000)
Change in estimate	307,000
ARO liability at end of year	10,963,000	9,506,000	9,563,000
Less: Current portion of ARO at end of year	(2,590,000)	(174,000)
Total long-term ARO at end of year	8,373,000	9,332,000
Liabilities incurred related to wells acquired	824,000
Tax Receivable Agreement
Cash savings to be paid under tax receivable agreement with JEH and the pre-IPO owners (as a percent)	85.00%
Benefits of cash savings retained under tax receivable agreement (as a percent)	15.00%
Liabilities recorded	0
Number of exchanges	0
Minimum
Other Property, Plant and Equipment
Estimated useful lives	3 years
Maximum
Other Property, Plant and Equipment
Estimated useful lives	10 years
Leasehold improvements
Other Property, Plant and Equipment
Gross other property, plant and equipment	1,060,000	983,000
Furniture, fixtures, computers and software
Other Property, Plant and Equipment
Gross other property, plant and equipment	2,491,000	2,204,000
Vehicles
Other Property, Plant and Equipment
Gross other property, plant and equipment	835,000	719,000
Aircraft
Other Property, Plant and Equipment
Gross other property, plant and equipment	910,000	1,295,000
Other
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 134,000	$ 134,000

XML

Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Non-employee members of Board Of Directors | Restricted stock

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 January 1, 2013		—		—
Granted		27	$	15.05
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2013		27	$	15.05

Management incentive plan | Management units | Management

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 January 1, 2013		710,767		$	3.62
Granted		911,654		$	15.00
Forfeited		(167,239	)	$	3.62
Vested		(998,032	)	$	9.96
Unvested at December 31, 2013		457,150		$	12.46

XML

Stock-based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended	0 Months Ended	12 Months Ended			12 Months Ended
	Dec. 31, 2013 Non-employee members of Board Of Directors Restricted stock	Sep. 04, 2013 Non-employee members of Board Of Directors Class A Restricted stock item	Dec. 31, 2013 Non-employee members of Board Of Directors Class A Restricted stock	Dec. 31, 2013 Non-employee members of Board Of Directors General and administrative expenses Restricted stock	Dec. 31, 2013 Management incentive plan Management units JEH Common Class B	Dec. 31, 2013 Management incentive plan Management units JEH General and administrative expenses	Dec. 31, 2012 Management incentive plan Management units JEH General and administrative expenses	Dec. 31, 2011 Management incentive plan Management units JEH General and administrative expenses	Dec. 31, 2013 Management incentive plan Management units JEH Management
Units/ Awards
Unvested at the beginning of the period (in shares)					457,150				710,767
Granted (in shares)	27								911,654
Forfeited (in shares)									(167,239)
Vested (in shares)									(998,032)
Unvested at the end of the period (in shares)	27				457,150				457,150
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)									$ 3.62
Granted (in dollars per share)	$ 15.05								$ 15.00
Forfeited (in dollars per share)									$ 3.62
Vested (in dollars per share)									$ 9.96
Unvested at the end of the period (in dollars per share)	$ 15.05								$ 12.46
Stock compensation expense				$ 0.1		$ 10.7	$ 0.6	$ 1.1
Number of non-employee members of the Board of Directors to whom awards were granted		4
Awards granted to each non-employee director (in shares)		6,645
Service period from date of grant			1 year

XML

Fair Value Measurement (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements
Current assets	$ 8,837	$ 17,648
Long-term assets	25,398	25,199
Current liabilities	10,664	4,035
Long-term liabilities	190	7,657
Level 2 | Commodity Price Hedges
Fair Value Measurements
Current assets	8,837	17,648
Long-term assets	25,967	24,756
Current liabilities	10,188	2,992
Long-term liabilities		6,739
Level 3 | Commodity Price Hedges
Fair Value Measurements
Long-term assets	(569)	443
Current liabilities	476	1,043
Long-term liabilities	190	918
Total | Commodity Price Hedges
Fair Value Measurements
Current assets	8,837	17,648
Long-term assets	25,398	25,199
Current liabilities	10,664	4,035
Long-term liabilities	$ 190	$ 7,657

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current tax expense
Federal	$ 85,000
Total current expense	85,000
Deferred tax expense (benefit)
Federal	(1,260,000)
State	1,104,000	473,000	173,000
Total deferred expense (benefit)	(156,000)	473,000	173,000
Total income tax provision	(71,000)	473,000	173,000
Tax benefit attributable to controlling interests	(1,223,000)
Tax expense attributable to non-controlling interests	1,152,000	473,000	173,000
Provision calculated at federal statutory income tax rate:
Net income before taxes	22,334,000	(2,606,000)	60,499,000
Statutory rate (as a percent)	35.00%
Income tax expense computed at statutory rate	7,817,000
Less: Noncontrolling interests	(9,009,000)
Income tax benefit attributable to Jones Energy, Inc.	(1,192,000)
State and local income taxes, net of federal benefit	(49,000)
Other	18,000
Tax benefit attributable to Jones Energy, Inc.	(1,223,000)
Tax expense attributable to non-controlling interest	1,152,000	473,000	173,000
Total income tax provision	(71,000)	473,000	173,000
Deferred tax assets
Investment in consolidated subsidiary JEH	526,000
Net operating loss	649,000
Alternative minimum tax credits	86,000
State deferred tax asset	52,000
Total deferred tax assets	1,313,000
Deferred tax liabilities
State deferred tax liability	3,093,000	1,936,000
Total deferred tax liabilities	3,093,000	1,936,000
Net deferred tax assets (liabilities)	(1,780,000)	(1,936,000)
Net deferred tax assets (liabilities)	(1,780,000)	(1,936,000)
Federal
Operating loss carry-forward
Net operating loss carry-forward	1,800,000
State
Operating loss carry-forward
Net operating loss carry-forward	$ 400,000

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

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 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").

Financial Instruments

        Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company's credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company's credit risk. Derivative instruments are recorded at fair value, as discussed below.

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 and believes the Company's risk is negligible.

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 consist primarily of 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, 2013 and 2012, 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. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 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, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% 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 is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that 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. Oil and gas properties consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

        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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

        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. The Company did not capitalize any interest in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        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 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. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        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 incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

        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 activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

        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 consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

        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. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

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, 2013, 2012 and 2011, 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 Jones 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 4, "Fair Value Measurement," for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

        The Company's asset retirement obligations 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. A summary of the Company's ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are 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.

Production Costs

        Production costs, including compressor rental, pumpers' salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

        Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

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 ASC 740-10-25, which requires the use of 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.

Tax Receivable Agreement

        In conjunction with the IPO, the Company entered into a Tax Receivable Agreement ("TRA") with JEH and the pre-IPO owners. Upon any exchange of JEH—Units and Class B common stock of the Company held by JEH's pre-IPO owners for Class A common stock of the Company, the TRA provides for the payment by the Company, directly to such exchanging owners, of 85% of the amount of cash savings in income or franchise taxes that the Company realizes as a result of (i) the tax basis increases resulting from the exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units for cash) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The Company will retain the benefit of the remaining 15% of the cash savings. Liabilities under the TRA will be recognized upon the exchange of shares. As of December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

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

Statement of Cash Flows

        The Company presents its cash flows using the indirect method.

Related Party Transactions

        In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker 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. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the 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 connection with the Company's entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

        JEH implemented a management incentive plan effective January 1, 2010, that provided membership-interest awards in JEH to members of senior management ("management units"). The management unit grants awarded prior to the initial filing of the registration statement in March 2013 had a dual vesting schedule. Sixty percent of the units awarded vested in five equal annual installments, with the remaining 40% vesting upon a company restructuring event, including the IPO. All grants awarded after the initial registration statement have a single vesting structure of five equal annual installments and were valued at the IPO price, adjusted for equivalent shares. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

        Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan, established in conjunction with the Company's IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards. As of December 31, 2013 no such awards had been issued or granted to any of the Company's employees.

        On September 4, 2013, the Company granted each of the four outside members of the Board of Directors 6,645 shares of restricted Class A common stock under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of the restricted stock grants 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 one-year vesting period.

        Refer to Note 7, "Stock-based Compensation," for additional information regarding the management units and restricted stock awards.

Business Combinations

        For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

        The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

        In December 2011, the Financial Accounting Standards Board ("FASB"), issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset arrangement. In January 2013, FASB issued an update to the previously issued guidance with the purpose of clarifying the scope of the disclosures about the offsetting assets and liabilities. The additional disclosures enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity's financial position. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013. The Company has provided all required disclosures for the periods presented as they pertain to its commodity derivative instruments (see Note 4, "Fair Value Measurement"). These disclosure requirements did not affect the Company's operating results, financial position, or cash flows.

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Earnings per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (numerator):
Net income (loss) applicable to controlling interests	$ (2,186)	$ (3,079)	$ 60,326
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic and diluted	12,500
Earnings (loss) per share:
Basic and diluted (in dollars per share)	$ (0.17)
Anti-dilutive restricted shares of Class A common stock	27

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Organization and Description of Business (Details)	12 Months Ended	0 Months Ended
	Dec. 31, 2013 item	Jul. 29, 2013 Pre-IPO owners of JEH item	Jul. 29, 2013 JEH
Organization and description of business
Number of classes of common stock	2
Exchange ratio		1
Number of votes for each holder of common stock		1
Economic interest (as a percent)			74.70%
Number of distinct basins where entity's assets are located	2

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes

Schedule of income tax provision

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State		—			—		—
Total current expense		85			—		—
Deferred tax expense (benefit)
Federal		(1,260	)		—		—
State		1,104			473		173
Total deferred expense (benefit)		(156	)		473		173
Total tax expense (benefit)		(71	)		473		173
Tax benefit attributable to controlling interests		(1,223	)		—		—
Tax expense attributable to non-controlling interests		1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

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)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate		35	%
Income tax expense computed at statutory rate		7,817
Less: Non-controlling interests		(9,009	)
Income tax benefit attributable to controlling interests		(1,192	)
State and local income taxes, net of federal benefit		(49	)
Other		18
Tax benefit attributable to controlling interests		(1,223	)
Tax expense attributable to non-controlling interests		1,152
Total income tax benefit	$	(71	)

Schedule of significant components of the Company's deferred tax assets and deferred tax liability

	As of December 31,
(in thousands of dollars)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss		649			—
Alternative minimum tax credits		86			—
State deferred tax asset		52			—
Total deferred tax assets		1,313			—
Deferred tax liabilities
State deferred tax liability		3,093			1,936
Total deferred tax liabilities		3,093			1,936
Net deferred tax assets (liabilities)		(1,780	)		(1,936	)
Valuation allowance		—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

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Monarch Investment (Details) (USD $)	12 Months Ended		0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013 Equity interests issued to the Company in connection with the marketing agreement	May 07, 2013 Equity interests issued to the Company in connection with the marketing agreement Equity interests Monarch Natural Gas Holdings, LLC	Dec. 31, 2013 Monarch	May 07, 2013 Monarch Equity interests issued to the Company in connection with the marketing agreement Equity interests Monarch Natural Gas Holdings, LLC
Monarch Investment
Estimated fair value of equity interests issued to the entity					$ 15,000,000
Equity interests distributed to the entity's owners (as a percent)			67.00%
Equity interests distributed to the entity's owners			10,000,000
Equity interests distributed to a member of management (as a percent)			16.00%
Equity interests reserved for distribution to management through incentive plan (as a percent)			17.00%
Compensation expense recognized under management distributions and incentive plan	2,719,000	300,000
Deferred revenue recorded	14,531,000	15,000,000
Amortization of deferred revenue				$ 500,000

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Organization and Description of Business (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest expense	$ 30,774	$ 25,292	$ 21,994
Net income (loss)	22,405	(3,079)	60,326
Accrued liabilities	10,805	5,255
Members' equity		428,400
Adjustment
Interest expense		600	800
Net income (loss)		(600)	(800)
Accrued liabilities		600	800
Members' equity		$ (1,400)	$ (600)

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Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012 item
Segment Information
Number of industry segments	1
Number of geographic areas in which the entity operates	1
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
Accounts receivable - Oil and gas sales | Credit risk
Concentration of Risk
Concentration risk (as a percent)	79.00%	92.00%
Number of customers	8	8
Accounts receivable - Joint interest owners | Credit risk
Concentration of Risk
Concentration risk (as a percent)	77.00%	72.00%
Number of customers	5	5

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Organization and Description of Business

12 Months Ended

Dec. 31, 2013

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, 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.

        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. 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.

        Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Jones Energy, Inc.'s initial public offering ("IPO") on July 29, 2013, the pre-IPO owners of JEH converted their existing membership interests in JEH into JEH Units and amended the existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH Units and to admit Jones Energy, Inc. as the sole managing member of JEH. Jones Energy, Inc.'s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. Only Class A common stock was offered to investors pursuant to the IPO. 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. The Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by the Company's stockholders generally. As a result of the IPO, the pre-IPO owners retained 74.7% 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 (loss) earned prior to the IPO date is reflected in the net income (loss) 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 acquisition, exploration, and production of oil and natural gas properties in the mid-continent United States. The Company's assets are located within two distinct basins in the Texas Panhandle and Oklahoma, the Anadarko Basin and the Arkoma Basin, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

        We identified an error in our previously issued financial statements which would have been material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period. Therefore we have revised our Consolidated Statement of Operations for the years ended December 31, 2012 and 2011 to record $0.6 million and $0.8 million, respectively of additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. As a result, net income decreased for the years ended December 31, 2012 and 2011 by $0.6 million and $0.8 million, respectively. The balance sheet impacts of the revision are increases in accrued liabilities and decreases in members' equity of $0.6 million and $1.4 million at December 31, 2011 and 2012, respectively. These revisions had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows. We have determined that these errors are not material to our consolidated financial statements for the years ended December 31, 2012 and 2011.

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Significant Accounting Policies (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013 item Boe	Dec. 31, 2012	Dec. 31, 2011
Mineral interests in properties
Unproved	$ 114,457,000	$ 137,254,000
Proved	958,816,000	737,558,000
Wells and equipment and related facilities	609,748,000	389,727,000
Gross oil and gas properties	1,683,021,000	1,264,539,000
Less: Accumulated depletion and impairment	(370,470,000)	(257,195,000)
Net oil and gas properties	1,312,551,000	1,007,344,000
Costs capitalized in connection with exploratory wells in progress	0	0
Minimum project period for capitalization of interest on expenditures	6 months
Number of projects for which interest on expenditure is capitalized	0
Amount of capitalized interest on expenditures		100,000
Number of cubic feet of gas considered as numerator in calculation of unit conversion ratio	6,000
Depletion of oil and gas properties	113,300,000	79,900,000	68,200,000
Impairment charges of proved oil and natural gas properties and equipment	0	18,800,000	19,800,000
Impairment charges related to unproved properties	$ 14,400,000	$ 0	$ 12,200,000
Oil and gas sales | PVR Midstream
Dependence on Major Customers
Concentration risk (as a percent)	15.00%	18.00%	22.00%
Oil and gas sales | Unimark LLC
Dependence on Major Customers
Concentration risk (as a percent)	13.00%	24.00%	13.00%
Oil and gas sales | Mercuria
Dependence on Major Customers
Concentration risk (as a percent)	13.00%	18.00%
Oil and gas sales | Valero Marketing
Dependence on Major Customers
Concentration risk (as a percent)	13.00%		9.00%
Oil and gas sales | Plains Marketing
Dependence on Major Customers
Concentration risk (as a percent)	6.00%	15.00%	27.00%

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Derivative Instruments and Hedging Activities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basis swaps | Low
Derivative instruments and hedging activities
Nonmonetary notional amount	320,000	320,000
Contract differential (in dollars per mmbtu)	(0.43)	(0.65)
Basis swaps | High
Derivative instruments and hedging activities
Nonmonetary notional amount	690,000	850,000
Contract differential (in dollars per mmbtu)	(0.11)	(0.03)
Basis swaps | Weighted Average
Derivative instruments and hedging activities
Nonmonetary notional amount	467,037	484,615
Contract differential (in dollars per mmbtu)	(0.34)	(0.31)
Oil | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	81.70	81.00
Nonmonetary notional amount	29,000	24,000
Oil | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	102.84	104.45
Nonmonetary notional amount	161,613	143,116
Oil | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	89.03	89.60
Nonmonetary notional amount	96,149	89,323
Natural gas | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	3.88	3.52
Nonmonetary notional amount	510,000	430,000
Natural gas | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	6.90	6.90
Nonmonetary notional amount	1,290,000	1,110,000
Natural gas | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	4.26	4.96
Nonmonetary notional amount	830,275	767,053
Natural gas liquids | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	6.72	6.72
Nonmonetary notional amount	2,000	2,000
Natural gas liquids | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	95.24	97.13
Nonmonetary notional amount	118,000	144,973
Natural gas liquids | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	32.98	33.81
Nonmonetary notional amount	46,646	55,616
Commodity derivatives
Derivative instruments and hedging activities
Net gains (Loss) recognized on derivative instruments	$ (2.6)	$ 16.7	$ 34.5

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash	$ 23,820	$ 23,726
Restricted Cash	45
Accounts receivable, net
Oil and gas sales	51,233	29,684
Joint interest owners	42,481	21,876
Other	1,459	4,590
Commodity derivative assets	8,837	17,648
Other current assets	2,392	1,088
Deferred tax assets	12
Total current assets	130,279	98,612
Oil and gas properties, net, at cost under the successful efforts method	1,312,551	1,007,344
Other property, plant and equipment, net	3,444	3,398
Commodity derivative assets	25,398	25,199
Other assets	15,006	16,133
Deferred tax assets	1,301
Total assets	1,487,979	1,150,686
Current liabilities
Trade accounts payable	89,430	38,036
Oil and gas sales payable	66,179	45,860
Accrued liabilities	10,805	5,255
Commodity derivative liabilities	10,664	4,035
Deferred tax liabilities		61
Asset retirement obligations	2,590	174
Total current liabilities	179,668	93,421
Long-term debt	658,000	610,000
Deferred revenue	14,531
Commodity derivative liabilities	190	7,657
Asset retirement obligations	8,373	9,332
Deferred tax liabilities	3,093	1,876
Total liabilities	863,855	722,286
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity		428,400
Additional paid-in-capital	173,169
Retained earnings (deficit)	(2,186)
Stockholders' / members' equity	171,033	428,400
Non-controlling interest	453,091
Total stockholders' / members' equity	624,124	428,400
Total liabilities and stockholders' / members' equity	1,487,979	1,150,686
Class A common stock
Stockholders' / members' equity
Common stock	13
Class B common stock
Stockholders' / members' equity
Common stock	$ 37

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 sqft	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies
Leased area of office space in Austin, TX (in square feet)	31,000
Future minimum payments for noncancellable operating leases
2014	$ 586,000
2015	482,000
2016	458,000
2017	147,000
Total	1,673,000
Rent expense under operating leases	$ 800,000	$ 800,000	$ 700,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net income (loss)	$ 22,405	$ (3,079)	$ 60,326
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Exploration expense			478
Depletion, depreciation, and amortization	114,136	80,709	68,906
Impairment of oil and gas properties	14,415	18,821	31,970
Accretion of discount	608	533	413
Amortization of debt issuance costs	2,677	3,544	2,940
Stock compensation expense	10,838	570	1,134
Other non-cash compensation expense (Note 9)	2,719
Amortization of deferred revenue	(469)
Gain on commodity derivatives	2,566	(16,684)	(34,490)
Gain on bargain purchase price			(26,208)
(Gain) loss on sales of assets	78	(1,162)	859
Deferred income tax provision	(156)	473	173
Other - net	79	129	(59)
Changes in assets and liabilities
Accounts receivable	(41,481)	11,568	(32,593)
Other assets	163	1,873	(3,360)
Accounts payable and accrued liabilities	35,318	(12,745)	49,728
Net cash provided by operations	163,896	84,550	120,217
Cash flows from investing activities
Additions to oil and gas properties	(197,618)	(125,493)	(157,046)
Acquisition of properties	(193,496)	(249,007)	(168,480)
Proceeds from sales of assets	1,607	9,158	6,747
Acquisition of other property, plant and equipment	(1,634)	(969)	(1,735)
Current period settlements of matured derivative contracts	7,586	28,675	1,551
Change in restricted cash	(45)
Net cash used in investing	(383,600)	(337,636)	(318,963)
Cash flows from financing activities
Proceeds from issuance of long-term debt	220,000	233,243	316,500
Repayment under long-term debt	(172,000)	(38,243)	(126,500)
Payment of debt issuance costs	(683)	(9,324)	(3,678)
Issuance of preferred units		85,000
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481
Net cash provided by financing	219,798	270,676	186,322
Net increase (decrease) in cash	94	17,590	(12,424)
Cash
Beginning of period	23,726	6,136	18,560
End of period	23,820	23,726	6,136
Supplemental disclosure of cash flow information
Cash paid for interest	25,414	20,759	18,151
Change in accrued additions to oil and gas properties	41,945	3,355	26,774
Noncash acquisition of oil and gas properties		2,918
Current additions to ARO	1,516	662	4,077
Noncash distributions to members (Note 9)	$ 10,000

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Significant Accounting Policies (Details 5)	0 Months Ended	12 Months Ended
	Sep. 04, 2013 item	Dec. 31, 2013
Management incentive plan | JEH | Management units | Common Class B
Stock Compensation
Unvested units and shares		457,150
Management incentive plan | JEH | Management units | Dual vesting
Stock Compensation
Percentage of units vesting in equal annual installments		60.00%
Vesting term		5 years
Percentage of units vesting upon restructuring event		40.00%
Management incentive plan | JEH | Management units | Single vesting
Stock Compensation
Vesting term		5 years
2013 Omnibus Incentive Plan | Class A common stock
Stock Compensation
Shares reserved (in shares)		3,850,000
Awards granted (in shares)		0
2013 Omnibus Incentive Plan | Restricted stock
Stock Compensation
Vesting term		1 year
Number of outside members of the Board of Directors to whom awards were granted	4
Awards granted, per outside member of the Board of Directors (in shares)	6,645

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Acquisition of Properties (Tables)

12 Months Ended

Dec. 31, 2013

Sabine acquisition

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved		154,724
Asset retirement obligations		(824	)
Total purchase price	$	193,496

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.

Chalker acquisition

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties
Unproved	$	71,264
Proved		182,493
Asset retirement obligations		(293	)
Total purchase price	$	253,464

Schedule of unaudited pro forma results of operations

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses		161,053
Operating income		33,632
Net income		25,713

Oil and natural gas properties located in Oklahoma

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations		(167	)
Total purchase price	$	154,058

Schedule of unaudited pro forma results of operations

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses		150,197
Operating income		26,687
Net income		62,408

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Acquisition of Properties (Details) (USD $)	12 Months Ended			0 Months Ended		12 Months Ended	0 Months Ended	12 Months Ended		0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 18, 2013 Sabine acquisition	Dec. 31, 2013 Sabine acquisition	Dec. 31, 2013 Sabine acquisition	Dec. 20, 2012 Chalker acquisition	Dec. 31, 2012 Chalker acquisition	Dec. 31, 2011 Chalker acquisition	Apr. 14, 2011 Oil and natural gas properties located in Oklahoma	Dec. 31, 2011 Oil and natural gas properties located in Oklahoma	Dec. 31, 2010 Oil and natural gas properties located in Oklahoma
Acquisition of Properties
Initial purchase price				$ 193,500,000			$ 251,900,000			$ 154,100,000
Oil and gas properties
Unproved				39,596,000			71,264,000			26,200,000
Proved				154,724,000			182,493,000			154,100,000
Oil and gas properties										154,225,000
Asset retirement obligations				(824,000)			(293,000)			(167,000)
Total purchase price				193,496,000			253,464,000			154,058,000
Purchase price placed in escrow account				24,000,000
Total fair value										180,300,000
Bargain purchase gain			26,208,000							26,200,000
Ownership interest in the undeveloped properties (as a percent)										50.00%
Post Acquisition
Total operating revenues	259,169,000	149,814,000	168,283,000		1,365,000
Total operating expenses	203,417,000	144,974,000	145,629,000		291,000
Operating income	55,752,000	4,840,000	22,654,000		1,074,000
Net income	(2,186,000)	(3,079,000)	60,326,000		1,074,000			(2,501,000)	61,130,000		61,130,000	24,780,000
Pro Forma
Total operating revenue						308,773,000		194,685,000			176,884,000
Total operating expenses						229,648,000		161,053,000			150,197,000
Operating income						79,125,000		33,632,000			26,687,000
Net income						$ 45,778,000		$ 25,713,000			$ 62,408,000

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.70		$	102.84		$	89.03
	Barrels per month		29,000			161,613			96,149		December 2017
Natural gas swaps	Exercise price	$	3.88		$	6.90		$	4.26
	mmbtu per month		510,000			1,290,000			830,275		December 2017
Basis swaps	Contract differential	$	(0.43	)	$	(0.11	)	$	(0.34	)
	mmbtu per month		320,000			690,000			467,037		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	95.24		$	32.98
	Barrels per month		2,000			118,000			46,646		December 2017

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month		24,000			143,116			89,323		December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month		430,000			1,110,000			767,053		December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month		320,000			850,000			484,615		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month		2,000			144,973			55,616		December 2017

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Consolidated Statements of Cash Flows (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Consolidated Statements of Cash Flows
Payment of stock issuance expenses	$ 15.1

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013
Class A common stock
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	12,526,580
Common Stock, shares outstanding	12,526,580
Class B common stock
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	36,836,333
Common Stock, shares outstanding	36,836,333

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Commitments and Contingencies

10. Commitments and Contingencies

Lease obligations

        The Company leases approximately 31,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for noncancellable operating leases extending beyond one year at December 31, 2013 are as follows:

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015		482
2016		458
2017		147
Thereafter		—
	$	1,673

        Rent expense under operating leases was $0.8 million, $0.8 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, 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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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 05, 2013 Class A common stock	Mar. 05, 2013 Class B common stock
Entity Registrant Name	Jones Energy, Inc.
Entity Central Index Key	0001573166
Document Type	10-K
Document Period End Date	Dec. 31, 2013
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	Non-accelerated Filer
Entity Public Float	$ 0
Entity Common Stock, Shares Outstanding		12,526,580	36,836,333
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Benefit Plans

12 Months Ended

Dec. 31, 2013

Benefit Plans

Benefit Plans

11. Benefit Plans

        The Company established a 401(k) tax-deferred 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. For the years ended December 31, 2013 and 2012, $0.3 million and $0.2 million were contributed, respectively, to the Plan.

        In 2013, the Company established a 409A tax-deferred savings plan for the benefit of key employees. This plan is a defined contribution plan, and the Company may match a portion of employee contributions. For the year ended December 31, 2013, the Company made a negligible contribution to this plan.

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues
Oil and gas sales	$ 258,063	$ 148,967	$ 167,261
Other revenues	1,106	847	1,022
Total operating revenues	259,169	149,814	168,283
Operating costs and expenses
Lease operating	27,781	23,097	21,548
Production taxes	12,865	5,583	5,333
Exploration	1,710	356	780
Depletion, depreciation and amortization	114,136	80,709	68,906
Impairment of oil and gas properties	14,415	18,821	31,970
Accretion of discount	608	533	413
General and administrative (including non-cash compensation expense)	31,902	15,875	16,679
Total operating expenses	203,417	144,974	145,629
Operating income	55,752	4,840	22,654
Other income (expense)
Interest expense	(30,774)	(25,292)	(21,994)
Net gain (loss) on commodity derivatives	(2,566)	16,684	34,490
Gain on bargain purchase			26,208
Gain (loss) on sales of assets	(78)	1,162	(859)
Other income (expense), net	(33,418)	(7,446)	37,845
Income (loss) before income tax	22,334	(2,606)	60,499
Income tax provision
Current	85
Deferred	(156)	473	173
Total income tax provision	(71)	473	173
Net income (loss)	22,405	(3,079)	60,326
Net income attributable to non-controlling interests	24,591
Net income (loss) attributable to controlling interests	$ (2,186)	$ (3,079)	$ 60,326
Earnings per share:
Basic and diluted (in dollars per share)	$ (0.17)
Weighted average shares outstanding:
Basic and diluted (in shares)	12,500

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

5. Derivative Instruments and Hedging Activities

        The Company had various commodity derivatives in place to offset uncertain price fluctuations that could affect its future operations as of December 31, 2013 and 2012, as follows:

Hedging Positions

	December 31, 2013
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.70		$	102.84		$	89.03
	Barrels per month		29,000			161,613			96,149		December 2017
Natural gas swaps	Exercise price	$	3.88		$	6.90		$	4.26
	mmbtu per month		510,000			1,290,000			830,275		December 2017
Basis swaps	Contract differential	$	(0.43	)	$	(0.11	)	$	(0.34	)
	mmbtu per month		320,000			690,000			467,037		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	95.24		$	32.98
	Barrels per month		2,000			118,000			46,646		December 2017

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month		24,000			143,116			89,323		December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month		430,000			1,110,000			767,053		December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month		320,000			850,000			484,615		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month		2,000			144,973			55,616		December 2017

        The Company recognized a net loss on derivative instruments of $2.6 million for the year ended December 31, 2013 and net gains of $16.7 million and $34.5 million for the years ended December 31, 2012 and 2011, respectively.

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Fair Value Measurement

12 Months Ended

Dec. 31, 2013

Fair Value Measurement

Fair Value Measurement

4. 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, 2013 and 2012, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	December 31, 2013
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)			Total
Commodity Price Hedges
Current assets	$	—	$	8,837	$	—		$	8,837
Long-term assets		—		25,967		(569	)		25,398
Current liabilities		—		10,188		476			10,664
Long-term liabilities		—		—		190			190

	December 31, 2012
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	17,648	$	—	$	17,648
Long-term assets		—		24,756		443		25,199
Current liabilities		—		2,992		1,043		4,035
Long-term liabilities		—		6,739		918		7,657

        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, 2013.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 per barrel

        Significant increases/decreases in natural gas liquid futures 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, 2013 and 2012. 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 January 1, 2012, net	$	(2,083	)
Purchases		(2,352	)
Settlements		—
Transfers to Level 2		2,370
Transfers to Level 3		834
Changes in fair value		(288	)
Balance at December 31, 2012, net		(1,519	)
Purchases		(1,095	)
Settlements		(210	)
Transfers to Level 2		(753	)
Changes in fair value		2,342
Balance at December 31, 2013, net	$	(1,235	)

        Transfers from Level 3 to Level 2 represent all of the Company's natural gas basis swaps for which observable forward curve pricing information has become readily available. In 2012, transfers to Level 3 represented natural gas liquid swaps or basis swaps that were classified as Level 2 in 2011 but due to the unavailability of forward prices in 2012, were classified as Level 3 in 2012. The purchases represent natural gas liquid swaps that the Company entered into in 2013 that do not have observable forward curve pricing information.

Offsetting Assets and Liabilities

        As of December 31, 2013, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, 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, 2013 and December 31, 2012:

(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, 2013
Commodity derivative contracts
Assets	$	38,071		$	(6,035	)	$	32,036		$	2,199		$	34,235
Liabilities		(14,347	)		6,035			(8,312	)		(2,542	)		(10,854	)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities		(17,928	)		7,831			(10,097	)		(1,595	)		(11,692	)

Nonfinancial Assets and Liabilities

        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. No significant impairment charges on the Company's proved properties were recorded during the year ended December 31, 2013. During 2012 and 2011, unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, the Company recorded charges of $18.8 million and $19.8 million during the years ended December 31, 2012 and 2011, respectively.

        Additionally, the Company reviews its unproved properties for indicators of impairment based on the Company's current exploration plans. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to the Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage and associated reserves. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content. With low natural gas prices during that period, the lack of natural gas liquids reduced the economic return of those fields and as a result, the Company had no intentions to continue development of those fields.

        Impairment charges are recorded on the Consolidated Statement of Operations. 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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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurement

Schedule of financial instruments carried at fair value

	December 31, 2013
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)			Total
Commodity Price Hedges
Current assets	$	—	$	8,837	$	—		$	8,837
Long-term assets		—		25,967		(569	)		25,398
Current liabilities		—		10,188		476			10,664
Long-term liabilities		—		—		190			190

	December 31, 2012
	Fair Value Measurements Using
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	17,648	$	—	$	17,648
Long-term assets		—		24,756		443		25,199
Current liabilities		—		2,992		1,043		4,035
Long-term liabilities		—		6,739		918		7,657

Schedule of quantitative information about Level 3 inputs used in the fair value measurement

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 per barrel

Schedule of changes in fair value of Level 3 financial instruments

(in thousands of dollars)
Balance at January 1, 2012, net	$	(2,083	)
Purchases		(2,352	)
Settlements		—
Transfers to Level 2		2,370
Transfers to Level 3		834
Changes in fair value		(288	)
Balance at December 31, 2012, net		(1,519	)
Purchases		(1,095	)
Settlements		(210	)
Transfers to Level 2		(753	)
Changes in fair value		2,342
Balance at December 31, 2013, net	$	(1,235	)

Schedule of commodity derivative contracts which are netted on 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, 2013
Commodity derivative contracts
Assets	$	38,071		$	(6,035	)	$	32,036		$	2,199		$	34,235
Liabilities		(14,347	)		6,035			(8,312	)		(2,542	)		(10,854	)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities		(17,928	)		7,831			(10,097	)		(1,595	)		(11,692	)

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

Income Taxes

12. Income Taxes

        Following its IPO, the Company began recording a federal and state income tax liability 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, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State		—			—		—
Total current expense		85			—		—
Deferred tax expense (benefit)
Federal		(1,260	)		—		—
State		1,104			473		173
Total deferred expense (benefit)		(156	)		473		173
Total tax expense (benefit)		(71	)		473		173
Tax benefit attributable to controlling interests		(1,223	)		—		—
Tax expense attributable to non-controlling interests		1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

        For the years ended December 31, 2012 and 2011, the reported taxes 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)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate		35	%
Income tax expense computed at statutory rate		7,817
Less: Non-controlling interests		(9,009	)
Income tax benefit attributable to controlling interests		(1,192	)
State and local income taxes, net of federal benefit		(49	)
Other		18
Tax benefit attributable to controlling interests		(1,223	)
Tax expense attributable to non-controlling interests		1,152
Total income tax benefit	$	(71	)

        For the years ended December 31, 2012 and 2011, the calculation is not applicable as the Company was not subject to federal income taxes prior to the IPO.

        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.

        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)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss		649			—
Alternative minimum tax credits		86			—
State deferred tax asset		52			—
Total deferred tax assets		1,313			—
Deferred tax liabilities
State deferred tax liability		3,093			1,936
Total deferred tax liabilities		3,093			1,936
Net deferred tax assets (liabilities)		(1,780	)		(1,936	)
Valuation allowance		—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

        The Company has a federal net operating loss carry-forward totaling $1.8 million and state net operating loss carry-forward of $0.4 million, both expiring in 2033. No valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize its deferred tax assets. This future taxable income will arise from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax basis. The Company may elect to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.

        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 2009, 2010, 2011, and 2012. The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Company is not currently under audit in any other major taxing jurisdiction.

        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, 2013 and December 31, 2012 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.

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Earnings per Share

12 Months Ended

Dec. 31, 2013

Earnings per Share

Earnings per Share

8. 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. Class B common stock is 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 dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. On September 4, 2013 (the "grant date"), the Company granted to its directors restricted shares of Class A common stock, which vest on the first anniversary of the grant date. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. For the year ended December 31, 2013, the directors' restricted shares of Class A common stock were excluded from the diluted calculation, as their inclusion would have been anti-dilutive as the Company was in a net loss position. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the year ended December 31, 2013. Net income (loss) and the weighted average number of shares of Class A common stock outstanding is based on the actual days in which the shares were outstanding for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted		12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock		27

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-Term Debt

Long-Term Debt

6. 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") which were subsequently amended on November 18, 2011, November 5, 2012, December 20, 2012, June 12, 2013, December 18, 2013 and January 29, 2014. In connection with the November 2012 amendment, the maturity date of the Revolver was extended to November 5, 2017 and the maturity date of the Term loan was extended to May 5, 2018. In connection with the June 2013 amendment, the borrowing base on the Revolver was increased to $500.0 million and subsequently increased to $575.0 million on December 18, 2013 in conjunction with the Sabine acquisition. The Company's oil and gas properties are pledged as collateral against these credit agreements.

        Terms of the Revolver require the Company to pay interest on the loan on the earlier of the London InterBank Offered Rate (LIBOR) tranche maturity date or three months, with the entire principal and interest due on the loan maturity date. Borrowings may be drawn on the principal amount up to the maximum available credit amount. Interest on the Revolver is calculated at a base rate (LIBOR or prime), plus a margin of 0.50% to 2.50% based on the actual amount borrowed compared to the borrowing base amount and the base rate selected. For the year ended December 31, 2013, the average interest rate under the Revolver was 3.01% on an average outstanding balance of $384.9 million. For the year ended December 31, 2012, the average interest rate under the Revolver was 3.30% on an average outstanding balance of $306.8 million.

        Terms of the Term Loan require the Company to pay interest on the loan every three months with the principal and interest due on the loan maturity date of May 5, 2018. Interest on the Term Loan is calculated at a base rate (LIBOR, prime, or federal funds), plus a margin of 6% to 7% based on the base rate selected. As of December 31, 2013, the average interest rate was 9.19% on an average outstanding balance of $160.0 million. As of December 31, 2012, the average interest rate was 9.16% on an average outstanding balance of $121.3 million.

        Total interest and commitment fees under the two facilities were $27.0 million, $21.2 million and $18.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        In connection with the IPO, the Company used the net proceeds to repay outstanding borrowings under the Revolver of $167.0 million.

        The Revolver and Term Loans are 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 and Term Loans approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

        The Revolver and Term Loans include covenants that require, among other things, restrictions on asset sales, distributions to members, and additional indebtedness, and the maintenance of certain financial ratios, including leverage, proven reserves to debt, and current ratio. The Company was in compliance with these covenants at December 31, 2013.

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Stock-based Compensation

12 Months Ended

Dec. 31, 2013

Stock-based Compensation

Stock-based Compensation

7. Stock-based Compensation

        JEH granted membership-interest awards in JEH to members of senior management ("management units") under a management incentive plan prior to the IPO. These awards had various vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date. As of December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock. The Units/shares will become convertible into a like number of shares of Class A common stock upon vesting. The following table summarizes information related to the Units/shares held by management:

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		710,767		$	3.62
Granted		911,654		$	15.00
Forfeited		(167,239	)	$	3.62
Vested		(998,032	)	$	9.96
Unvested at December 31, 2013		457,150		$	12.46

        Stock compensation expense associated with the management units for the years ended December 31, 2013, 2012 and 2011 was $10.7 million, $0.6 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

        On September 4, 2013, the Company granted restricted stock awards to non-employee members of the Board of Directors. Each of the four directors was awarded 6,645 restricted shares of Class A common stock, contingent on the director serving as a director of the Company for a one-year service period from the date of grant. The fair value of the awards was based on the value of the Company's Class A common stock on the date of grant. The total value of the awards to the directors is as follows:

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		—		—
Granted		27	$	15.05
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2013		27	$	15.05

        Stock compensation expense associated with the Board of Directors awards for the year ended December 31, 2013 was $0.1 million and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

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Monarch Investment

12 Months Ended

Dec. 31, 2013

Monarch Investment

Monarch Investment

9. Monarch Investment

        On May 7, 2013, the Company entered into a marketing agreement with Monarch Natural Gas, LLC ("Monarch"), a company related through common ownership, for the sale to Monarch of natural gas produced from certain properties. In connection with that agreement, Monarch issued to the Company equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the issuance of the equity interests, the Company distributed 67% or $10 million of the Monarch equity interests to the Company's owners pro rata based on equity contributions and approximately 16% of the interests to a member of management. The remaining approximately 17% of the equity interests were reserved for distribution to management through an incentive plan. The Company recognized $0.3 million of compensation expense during the year ended December 31, 2013 in connection with the incentive plan. In addition, the Company recorded deferred revenue of $15.0 million which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of production sales to Monarch. The Company amortized $0.5 million of the deferred revenue balance during the year ended December 31, 2013 and is recorded in other revenues on the Company's Consolidated Statement of Operations.

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Significant Accounting Policies (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended						0 Months Ended		0 Months Ended
	Dec. 31, 2013 MMBoe	Dec. 31, 2013 Boe	Dec. 31, 2013 Metalmark item	Dec. 31, 2012 Metalmark	Dec. 31, 2011 Metalmark	Dec. 31, 2013 Metalmark Minimum	Sep. 01, 2013 Monarch	May 07, 2013 Monarch Metalmark	May 07, 2013 JEH	May 07, 2013 JEH Monarch
Related Party Transactions
Annual administration fee			$ 0.7	$ 0.7	$ 0.7
Production of natural gas and NGLs from the Chalker properties (in MMBoe)	0.8	6,000
Initial term of the agreement							10 years
Outstanding equity interests held (as a percent)								81.00%
Outstanding equity interests held by the related party (as a percent)						5.00%
Number of directors who are managing directors of the related party			2
Deemed value of equity interests issued										15
Value of equity interests assigned to Jonny Jones									2.4
Value of equity interests reserved to a benefit 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

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies

Schedule of oil and gas properties

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

Schedule of other property, plant and equipment

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

Summary of the Company's ARO

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

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Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings per Share

Schedule of calculation of the basic and diluted weighted-average shares and EPS

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted		12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock		27

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Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009 item	Dec. 31, 2013 Revolver	Dec. 31, 2012 Revolver	Dec. 19, 2013 Revolver	Jun. 12, 2013 Revolver	Dec. 31, 2013 Revolver Base rate	Dec. 31, 2013 Revolver Base rate Minimum	Dec. 31, 2013 Revolver Base rate Maximum	Dec. 31, 2013 Term Loan	Dec. 31, 2012 Term Loan	Dec. 31, 2013 Term Loan Base rate	Dec. 31, 2013 Term Loan Base rate Minimum	Dec. 31, 2013 Term Loan Base rate Maximum
Credit agreements
Number of credit agreements	2			2
Borrowing base							$ 575.0	$ 500.0
Frequency of interest payments					3 months							3 months
Reference rate									base rate (LIBOR or prime)					base rate (LIBOR, prime, or federal funds)
Margin interest rate (as a percent)										0.50%	2.50%				6.00%	7.00%
Average interest rates (as a percent)					3.01%	3.30%
Average outstanding balance					384.9	306.8						160.0	121.3
Average interest rate (as a percent)												9.19%	9.16%
Total interest and commitment fees	27.0	21.2	18.2
Repayment of borrowings					$ 167.0

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Consolidated Statement of Changes In Stockholders' / Members' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock Class A common stock	Common Stock Class B common stock	Members' Equity	Additional Paid-in-Capital	Retained Deficit	Non-controlling interest
Balance at Dec. 31, 2010	$ 284,449			$ 284,449
Increase (Decrease) Stockholders' / members' equity
Stock-compensation expense	1,134			1,134
Net income (loss)	60,326			60,326
Balance at Dec. 31, 2011	345,909			345,909
Increase (Decrease) Stockholders' / members' equity
Issuance of Class C Preferred Units	85,000			85,000
Stock-compensation expense	570			570
Net income (loss)	(3,079)			(3,079)
Balance at Dec. 31, 2012	428,400			428,400
Increase (Decrease) Stockholders' / members' equity
Issuance of common stock	50	13	37
Issuance of common stock (in shares)		12,500	36,836
Proceeds from the sale of common stock	172,431				172,431
Reclassification of members' contributions				(464,037)			464,037
Stock-compensation expense	10,838			10,100	738
Distribution to members	(10,000)			(10,000)
Net income (loss)	22,405			35,537		(2,186)	(10,946)
Balance at Dec. 31, 2013	$ 624,124	$ 13	$ 37		$ 173,169	$ (2,186)	$ 453,091
Balance (in shares/units) at Dec. 31, 2013		12,500	36,836

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Acquisition of Properties

12 Months Ended

Dec. 31, 2013

Acquisition of Properties

Acquisition of Properties

3. Acquisition of Properties

        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 an adjusted purchase price of $193.5 million (referred to herein as the "Sabine acquisition" or "Sabine"), subject to customary closing adjustments. The acquired assets include both producing properties and undeveloped acreage. The purchase was financed with borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved		154,724
Asset retirement obligations		(824	)
Total purchase price	$	193,496

        This acquisition qualified as a business combination under ASC 805. The valuation to determine the fair value was 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 current market. The determination of fair value is dependent on factors as of the acquisition date and the final adjustments to the purchase price, which when they occur, may result in an adjustment to the value of the acquired properties reflected in the consolidated financial statements. Any such adjustment may be material.

        In connection with the closing, approximately $24 million of the purchase price was placed in an escrow account. This amount represented the allocated value of the Sabine properties that had unresolved title defects claimed by JEH. In the event one or more title defects are not cured by Sabine, the affected property will be reconveyed to Sabine and the Company will receive an amount of cash from the escrow account equal to the allocated value of the reconveyed property. A corresponding adjustment to the allocation of the Sabine purchase price will be made at such time.

        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.

        On December 20, 2012, JEH acquired certain oil and natural gas properties located in Texas for a purchase price of $251.9 million (referred to herein as the "Chalker acquisition" or "Chalker"). The acquired assets included both producing properties and undeveloped acreage. The purchase was financed with additional equity capital and borrowings under the senior secured credit facility. In the second quarter of 2013, the Company made a final determination with the sellers as to the purchase price adjustments resulting in a final purchase price of $253.5 million. The final purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	71,264
Proved		182,493
Asset retirement obligations		(293	)
Total purchase price	$	253,464

        This acquisition qualified as a business combination under ASC 805. The valuation to determine the fair value was 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 current market.

        The unaudited pro forma results presented below have been prepared to include the effect of the Chalker acquisition on our results of operations for the year ended December 31, 2012. 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, 2012 or to project our results of operations for any future date or period.

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses		161,053
Operating income		33,632
Net income		25,713

        On April 14, 2011, Jones Energy acquired certain oil and natural gas properties located in Oklahoma for a purchase price of $154.1 million. The acquisition included both producing and undeveloped properties. The purchase was financed with additional borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations		(167	)
Total purchase price	$	154,058

        This acquisition qualified as a business combination under ASC 805. The Company recorded a total fair value of $180.3 million ($154.1 million for producing properties and $26.2 million for undeveloped property). The total resulted in a bargain purchase gain of $26.2 million, which was recorded in the Consolidated Statement of Operations. The valuation to determine the fair value was principally based on the discounted cash flows of the both 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 current market. The recognized gain was the difference between the net fair value and the consideration paid the seller.

        Management believes the bargain purchase gain resulted from the fact that the seller, who retained a 50% ownership interest in the undeveloped properties, benefitted from the Company's available liquidity that would enable accelerated development of the prospect.

        The following income statement line items present the pro forma results as if these properties had been acquired on January 1, 2010:

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses		150,197
Operating income		26,687
Net income		62,408

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Schedule of future minimum payments for noncancellable operating leases extending beyond one year

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015		482
2016		458
2017		147
Thereafter		—
	$	1,673

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Fair Value Measurement (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural gas liquid | Swap | Minimum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	6.72	6.72
Natural gas liquid | Swap | Maximum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	95.24	97.13
Commodity derivatives
Quantitative Information About Level 3 Fair Value Measurements
Fair Value	$ 14,347	$ 17,928
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap
Quantitative Information About Level 3 Fair Value Measurements
Fair Value	$ (1,235)
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap | Minimum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	9.24
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap | Maximum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	83.06

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

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, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

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 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").

Financial Instruments

Financial Instruments

        Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company's credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company's credit risk. Derivative instruments are recorded at fair value, as discussed below.

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 and believes the Company's risk is negligible.

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 consist primarily of 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, 2013 and 2012, 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. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 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, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% 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 is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that 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. Oil and gas properties consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

        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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

        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. The Company did not capitalize any interest in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        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 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. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        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 incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

        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 activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

        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 consisted of the following at December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

        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. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

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, 2013, 2012 and 2011, 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 Jones 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 4, "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 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. A summary of the Company's ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

Revenue Recognition

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are 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.

Production Costs

Production Costs

        Production costs, including compressor rental, pumpers' salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

Exploration Expenses

        Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

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 ASC 740-10-25, which requires the use of 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.

Tax Receivable Agreement

Tax Receivable Agreement

        In conjunction with the IPO, the Company entered into a Tax Receivable Agreement ("TRA") with JEH and the pre-IPO owners. Upon any exchange of JEH—Units and Class B common stock of the Company held by JEH's pre-IPO owners for Class A common stock of the Company, the TRA provides for the payment by the Company, directly to such exchanging owners, of 85% of the amount of cash savings in income or franchise taxes that the Company realizes as a result of (i) the tax basis increases resulting from the exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units for cash) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The Company will retain the benefit of the remaining 15% of the cash savings. Liabilities under the TRA will be recognized upon the exchange of shares. As of December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

Comprehensive Income

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

Statement of Cash Flows

Statement of Cash Flows

        The Company presents its cash flows using the indirect method.

Related Party Transactions

Related Party Transactions

        In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker 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. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the 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 connection with the Company's entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

Stock Compensation

        JEH implemented a management incentive plan effective January 1, 2010, that provided membership-interest awards in JEH to members of senior management ("management units"). The management unit grants awarded prior to the initial filing of the registration statement in March 2013 had a dual vesting schedule. Sixty percent of the units awarded vested in five equal annual installments, with the remaining 40% vesting upon a company restructuring event, including the IPO. All grants awarded after the initial registration statement have a single vesting structure of five equal annual installments and were valued at the IPO price, adjusted for equivalent shares. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

        Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan, established in conjunction with the Company's IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards. As of December 31, 2013 no such awards had been issued or granted to any of the Company's employees.

        On September 4, 2013, the Company granted each of the four outside members of the Board of Directors 6,645 shares of restricted Class A common stock under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of the restricted stock grants 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 one-year vesting period.

        Refer to Note 7, "Stock-based Compensation," for additional information regarding the management units and restricted stock awards.

Business Combinations

Business Combinations

        For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

Recent Accounting Developments

        The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

Offsetting Assets and Liabilities

        In December 2011, the Financial Accounting Standards Board ("FASB"), issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset arrangement. In January 2013, FASB issued an update to the previously issued guidance with the purpose of clarifying the scope of the disclosures about the offsetting assets and liabilities. The additional disclosures enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity's financial position. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013. The Company has provided all required disclosures for the periods presented as they pertain to its commodity derivative instruments (see Note 4, "Fair Value Measurement"). These disclosure requirements did not affect the Company's operating results, financial position, or cash flows.