10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

☒    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the annual period ended: December 31, 2015

OR

☐    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: 333-173751

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

Texas	20-3565150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 281-530-0991

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

None

Securities registered pursuant to Section 12(g) of the 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    ☒  No

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

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  ☐    No  ☒

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant 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 would have been required to file such reports) as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  ☒    No   ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405 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.  ☒

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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

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

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

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
	PART II
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	54
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	54
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accountant Fees and Services	66
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	66

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “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.

Forward-looking statements may include statements about our:

· business strategy;

· reserve quantities and the present value of our reserves;

· financial strategy, liquidity and capital required for our development program;

· future oil and natural gas prices;

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

· hedging strategy and results;

· future drilling plans;

· marketing of oil and natural gas;

· leasehold or business acquisitions;

· costs of developing our properties; 

· liquidity and access to capital;

· future operating results; and

· 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, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment and services, environmental risks, weather 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, reductions in cash flow, access to capital, and the other risks described under “Item 1A. 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. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Commodity prices began to decline beginning in the third quarter of 2014, continued to decline throughout 2015, and have been trading at multi-year lows thus far into the first quarter of 2016.  Current prices for oil andnatural gas are below the average calculated for 2015, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may reduce the estimated quantities and present values of our reserves. 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 may issue.

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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.

PART I

Item 1. Business

Our Company

Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is a privately held company engaged primarily in onshore oil and natural gas acquisition, exploitation, exploration and production whose focus is to maximize the profitability of our assets in a safe and environmentally sound manner. We seek to maintain a portfolio of assets in plays with known resources where we identify a large inventory of lower risk drilling, development, and enhanced recovery and exploitation opportunities. Our operations are located within the continental United States.  Our portfolio of assets has large components of liquids-rich gas and oil reservoirs.  Our core producing properties are located in Oklahoma and Louisiana. We believe there are decades of future development potential in our balanced portfolio of assets — principally historically prolific fields in the Sooner Trend in Oklahoma and the Weeks Island Area in South Louisiana. We maximize the profitability of our assets by focusing on sound engineering, enhanced geological techniques including 3-D seismic analysis, and proven drilling, stimulation, completion, and production methods.

As of December 31, 2015, our estimated total proved oil and natural gas reserves were approximately 78.5 MMBOE, of which 43% were classified as proved developed reserves. Our proved reserve mix is approximately 44% oil, 33% natural gas, and 23% natural gas liquids.  We maintain operational control of the majority of our properties.

Our areas of focus are typically characterized by multiple hydrocarbon pay zones, and because in many cases we are re-developing fields and areas originally discovered and developed by major oil and natural gas companies and other independent producers, our assets are typically served by existing infrastructure. As a result, we believe that our business model lowers geological, mechanical, and market-related risks. We focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating and capital costs. Additionally, we have consistently created value through workovers and re-completions of existing wells, infill drilling, operations improvements, secondary recovery and 3-D seismic-driven drilling. We expect to continue production growth in our core areas by exploiting known resources with continued well workovers, development drilling, and disciplined exploration.

Overview of 2015

During 2015, we concentrated our efforts on developing our core properties:the Sooner Trend field and the Weeks Island Area.  We continue to emphasize oil-rich reserves and production.  Highlights from 2015 include:

· estimated proved reserves increased by 21.6 MMBOE or 38% over 2014 year-end, primarily as a result of our focus on the successful drilling activity and development of our core property in the Sooner Trend;

· percentage of total production attributable to oil and natural gas liquids increased from 64% in 2014 to 71% in 2015, measured on the traditional energy content ratio of 6:1 between natural gas and oil;

· total average production from our two core properties of approximately 13.4 MBOEPD in 2015 as compared to 9.8 MBOEPD in 2014;

· oil production increased 11% from 3.8 MMBbl as of year-end 2014 to 4.2 MMBbl as of year-end 2015;

· total revenues from hydrocarbons decreased 44%in 2015 over 2014, primarily as a result of significant decrease in commodity prices;

· drilled 82 gross wells (45.4net wells) in 2015 of which 51 gross wells (34.0 net wells) were in our two core properties;

· approximately $238 million was invested in our oil and natural gas properties in 2015, as compared to $411 million in 2014 (both totals include acquisitions);

· recognized impairment expense in 2015 of $176.8 million as compared to $74.9 million in 2014

Recent Acquisitions and Divesture Activity

Our acquisitions and divestitures during2015 are summarized below.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K for additional information on these acquisitions and divestitures.

Divestiture. On September 30, 2015, we closed the sale of all the membership interests in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary that held all our remaining interests in the Eagle Ford shale play in Karnes County, Texas, effective July 1, 2015 (the “Effective Date”), for an aggregate cash purchase price of $125 million subject to certain adjustments, consisting of $118

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million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million payable to us by the 15th of each calendar month in which certain amounts owed to us prior to the Effective Date have been received.  As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million.  Cash received was utilized to pay down borrowings under our credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.

The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes gain on sale of asset of $67.6 million and $118.5 million in pre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture sold during the year ended December 31, 2014. 

Acquisition.  On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma.  The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments.  The effective date of the acquisition was April 1, 2015.  The purchase was funded with borrowings under our credit facility.  

Recent Developments

On January 13, 2016, our wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”) with BCE-STACK Development LLC (“BCE”), to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches.

Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate (each, a “Joint Well”), provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well.

On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million. The terms and conditions are the same as those of the first two tranches.

On March 16, 2016, we borrowed $141.9 million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility.  As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the Administrative Agent.  Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account.  These funds are intended to be used for general corporate purposes.

Following the funding of this borrowing, the aggregate principal amount of borrowings under the credit facility was $300 million, including $6.1 million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.

Industry Operating Environment and Outlook

The success of our business is highly dependent on the price we receive for our oil, natural gas liquids and natural gas.  Commodity prices began to decline beginning in the third quarter of 2014, continued to decline throughout 2015, and have been trading at multi-year lows thus far into the first quarter of 2016, with crude oil prices falling below $30.00 per barrel on several occasions.  These lower commodity prices have brought significant and immediate changes affecting our industry.  Low commodity prices affect our business in numerous ways, including:

· a significant reduction in our revenues and cash flows;

· some of our developed wells and undeveloped wells may become uneconomic;

· capital to develop reserves may be reduced;

· proved reserves may be reduced;

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· impairments of our oil and natural gas properties may increase;

· our cost of capital may become more expensive and access to capital may become more difficult, including from possible decreases in the borrowing base under our revolving credit facility; and

· an increase in the possibility that some of the purchasers of our oil and natural gas production, or some of the companies that provide us with services, will experience financial difficulties.

In response to the lower oil and natural gas prices, we have taken a number of actions to conserve our liquidity, including:

· reducing near term capital expenditures;

· actively seeking alternative sources of capital to develop our proved undeveloped reserves;

· negotiating lower costs from service companies and other vendors; and

· managing capital expenditures on operated properties we control.

We have continued to reduce our capital expenditures and operating costs in response to sustained low commodity prices, and our long term strategy remains intact.  While we cannot predict the length or depth of the current price decline, or the timing and extent of a potential price rebound, we have moved quickly and decisively regarding what we can control: our operating costs and the timing and levels of capital spending on projects we operate or control.  We will continue to monitor our capital spending closely based on actual and projected cash flows and could make additional reductions to our 2016 capital spending should commodity prices decrease further.  Conversely, a significant improvement in commodity prices could result in an increase in our capital expenditures.  See Item 1A. Risk Factors below.

For a more in-depth discussion of 2015 results, and our capital resources and liquidity, please see “Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.”

In response to this commodity price environment and in order to preserve our liquidity, we have reduced our anticipated capital expenditures for 2016 to $115 million from $148 million for 2015, a decrease of approximately 22%.  Our estimated capital expenditures for 2016 are allocated as follows:

· approximately $95 million to be spent in Sooner Trend;

· approximately $10 million to be spent in Weeks Island Area; and,

· approximately $10 million to be spent on various non-core properties.

Our Strategy

Our objective is to increase reserves and production by applying sound engineering and geological analyses, combined with safe and cost-effective operations, in areas we have identified as under-developed and over-looked.

· Exploit Known Resources in a Repeatable Manner. The majority of our assets are in mature fields previously developed by major oil and natural gas companies or other independent producers, prior to the advent of newer technology that can be applied today. Our objective is to enhance existing production in these properties by using our engineering and geological expertise to convert undeveloped reserves to active production, and to efficiently reduce operating and capital costs. We leverage previous experience and knowledge to continually improve our operations and guide our future development and expansion.

· Maximize Development Opportunities with Sound Engineering and Technology. We seek to exploit and redevelop mature properties by using state-of-the-art technologyincluding horizontal drilling, multi-stage hydraulic fracturing, 2-D and 3-D seismic imaging and advanced seismic modeling. We apply sound engineering and geologic science to define the appropriate application of appropriate recovery techniques, including recompletions, infill/step out drilling, horizontal drilling, and/or secondary recovery methods to enhance oil and natural gas production. Our geologists, geophysicists, engineers, and petrophysicists systematically integrate reservoir performance data with geologic and geophysical data, an approach that reduces drilling risks, lowers finding costs and provides for more efficient production of oil and natural gas from our properties.

· Create High-Potential, High-Impact Opportunities while Mitigating Exploration Risk. We target high impact prospects that offer an opportunity to significantly grow reserves. We minimize exploration risk by obtaining and synthesizing engineering, geologic, and seismic data to create a robust knowledge of producing zones in and around our prospective areas. We seek multiple targets in a given exploratory well to maximize and prolong the impact of our capital spending, and seek exploration opportunities that will, upon success, lead to multiple development wells. We diversify our risk across a number of prospects and further mitigate risk by typically bringing in industry partners to participate in our exploration prospects.

· Optimize Production Mix Based on Market Conditions. Our asset base enables us to efficiently and rapidly adjust our development activity in response to market prices. Despite the recent oil price decline, we intend to continue to exploit oil and natural gas liquids opportunities within our portfolio. Oil and natural gas liquids together represented 71% of our 4

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2015 production, measured on the traditional energy content ratio of 6:1 between natural gas and crude oil.  Oil and liquids-rich gas opportunities represented approximately 75% of our 2015 capital budget and represent approximately 72%of our 2016 capital budget. Commodity mix is a key consideration as we continually evaluate future drilling and acquisition opportunities in light of market price fluctuations.

· Pursue Value-Based Acquisitions that Leverage Current Internal Knowledge. We pursue acquisition targets where our own field exploitation methods can be profitably employed, and identify properties that other energy companies may consider lower-valued and/or non-strategic. We seek to control operations, and also engage in partnerships with other capable operators and service providers so we can capitalize on their data, knowledge and access to equipment.

· Mitigate Commodity Price Risk. Due to the potential for low oil and natural gas prices, we periodically enter into derivative transactions for a portion of our planned future oil, natural gas and natural gas liquids production. This allows us to reduce exposure to low prices and achieve more predictable cash flows. We retain commodity price upside potential through active management of our portfolio of derivative transactions, as well as through future production and reserve growth. As of December 31, 2015, we have hedged approximately 72% of our forecasted production from proved developed producing properties (“PDP”) through 2019 at average annual floor prices ranging from $2.92per MMBtu to $4.50per MMBtu for natural gas and $62.50per Bbl to $72.27per Bbl for oil.

· Maintain Financial Flexibility. In order to maintain our financial flexibility, we plan to fund our 2016 capital budget predominantly with cash flow from operations supplemented by borrowings under our credit facility, Term Loan Facility, non-strategic assets sales, and cash on hand. Our operational control of most properties enables us to manage the timing of a substantial portion of our capital investments. At December 31, 2015, under our senior secured revolving credit facility, we had $152 million in borrowings outstanding and $148 million available for borrowing.On March 16, 2016, we borrowed $141.9 million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility. 

Our Strengths

We believe that the following strengths provide us with significant competitive advantages and position us to continue to achieve our business objective and execute our strategies:

· Proven Track Record of Reserves and Production Growth. We have increased production at a compounded annual rate of approximately 23% since 2008 through a focused program of drilling and field re-development complemented by strategic acquisitions. Based on our long-term historical performance and our business strategy, we believe we have the opportunities, experience and knowledge to continue growing both our reserves and production.

· High Quality Portfolio of Under-Exploited Properties and Multi-Year, Low-Risk Drilling and Wellbore Utilization Inventory. The bulk of our assets are producing properties with significant opportunities for additional exploitation and exploration. We have created and expect to maintain a multi-year drilling inventory and a continuing program of well recompletions, typically to shallower productive zones as deeper formations deplete over time. As of December 31, 2015, our inventory of proved reserve projects consists of 146proved undeveloped reserves (“PUD”) locations, including 135 PUD locations in the Sooner Trend, and 8 PUD locations in Weeks Island Area. We believe that we have significant additional development opportunities that are not classified as proved reserves. By targeting productive zones in multiple stacked pays, we are able to minimize exploration risk and costs.

· Geographically and Geologically Balanced Asset Base. We have a balanced portfolio of low-risk conventional and high-impact resource assets across various historically productive basins. Our core assets are located in the Sooner Trend in Oklahoma, where our assets are in the Mississippian age Osage, Meramec, and Manning;the Pennsylvanian age Oswego Lime; the Hunton Lime; legacy waterflooded zones with shallow declines;and other formations;and in South Louisiana, where our most significant field is Weeks Island, a large oil field with multiple stacked pay sands. Our core properties are located in areas that benefit from an experienced and well-established service sector, efficient state regulation, and available midstream infrastructure and services. In addition, based on our reserve report as of December 31, 2015, approximately 84% of our total future net undiscounted revenues are expected to be from the production of proved oil and natural gas liquids reserves. We believe our geographic and geologic diversification enables us to allocate our capital more profitably, manage market, weather and regulatory risks, and capitalize on technological improvements.

· Strong Management Team and Seasoned Technical Expertise. We have an experienced and technically-adept management team, averaging more than 25 years of industry experience among our top eight executives. We have built a strong technical staff of geologists and geophysicists, field operations managers, and engineers in all relevant disciplines. Our engineers and operations staff typically began their careers with major oil companies, large independent producers, or leading service companies, and have direct experience in our areas of operation. We believe our engineers are among the best in their respective fields.

Partnership Structure

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We are structured as a private partnership.  Since our inception, we have funded exploration, development and operating activities primarily through cash from operations, as well as capital raised from equity contributed by our founder, capital contributed by a private equity partner, borrowings under our bank credit facilities, and proceeds from the issuance of $450 million principal amount of senior secured notes. 

Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our sole Class B partner is High Mesa, Inc. (“High Mesa”).On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our Board of Directors includes one member nominated by Highbridge and four members nominated by the Class A partners. 

Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). In connection with the recapitalization on March 25, 2014, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until certain provisions are met.  After such provisions are met, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the partnership agreement.

The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility, term loan facility, and our senior notes.

Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

Reserve and Production Overview

The following table describes our proved reserves and production profile as of December 31, 2015:  

	Total		Oil and					Average
	Estimated		NGLs as %					Daily Net
	Proved		of Total		PV-10		Net	Production
	Reserves	% Proved	Proved		($ in millions)	Net	Producing	2015
	(MMBOE)	Developed (1)	Reserves (1)		(2)	Acreage (3)	Wells (4)	(MBOE/d)
Sooner Trend	67.0	37%	68%	$	538.9	73,513	267.3	8.8
Weeks Island Area	6.0	69%	92%		91.1	12,358	39.7	4.6
Other	5.5	85%	29%		(0.4)	401,345	84.9	5.4
All Properties	78.5	43%	67%	$	629.6	487,216	391.9	18.8

(1) Computed as a percentage of total reserves of the property.

(2) PV-10 was calculated using oil and natural gas price parameters established by current Securities and Exchange Commission(“SEC”) guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended December 31, 2015. Because we are a partnership and, as such, are not subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes.  Calculation of PV-10 does not give effect to derivatives transactions.  The unweighted arithmetic average prices as of the first of each month during the twelve months ended December 31, 2015 were $50.28 per Bbl of oil and $2.58 per MMBtu of natural gas. 

(3) Includes developed and undeveloped acreage.

(4) Calculated as gross wells times our working interest percentage.

Our Properties

Sooner Trend, Oklahoma

Our assets in the Sooner Trend of Oklahoma are large, contiguous acreage blocks with multiple productive zones at depths generally between 4,000 feet and 8,000 feet.  These assets have historically been predominantly shallow-decline, long-lived oil fields originally drilled on 80-acre vertical well spacing and waterflooded to varying degrees.

Our focus in these fields is on continued implementation of a multi-year, multi-rig program to develop several pay zones with horizontal drilling and multi-stage hydraulic fracturing of the Mississippian age Osage, Meramec, and Manning and the Pennsylvanian age Oswego, as well as the definition of similar exploitation opportunities in the Woodford Shale, Hunton Lime, and other formations.  We also maintain production in the historically principal field pay zones that have been water flooded for several decades.  We have

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increased our acreage in the Sooner Trend to position ourselves for expanded horizontal development of stacked pays, both within and contiguous with our legacy position, including approximately 19,000 net acres in July 2015.

As of December 31, 2015, we had a 70% average working interest in 381 gross producing wells, and had identified 135 PUD locations in this area. We produced 3,218 MBOE net to us from our properties in Oklahoma in 2015, an increase of 86% as compared to 1,734 MBOE in 2014.

During 2015, we spent approximately $105million in the Sooner Trend for the drilling and completion of wells, as well as other expenditures for facilities.  As of December 31, 2015, we had twodrilling rigs operating in Sooner Trend for horizontal development.    Currently, we continue to havethree drilling rigs operating in Sooner Trend and plan to bring onone or twoadditional drilling rigs.  We plan to utilize up to five drilling rigs during 2016 targeting the Mississippian age Osage, Meramec, and Manning, and the Pennsylvanian age Oswego with horizontal drilling.We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage.We have allocated approximately $95 million of our 2016 capital expenditure budget to our Sooner Trend properties.  We plan to drill and complete up to 30 wells under our allocated 2016 capital expenditure budget for Sooner Trend.  We will also drill and complete up to 60 additional wells financed through our Joint Development Agreement with BCE at a cost of up to $192 million.

Weeks Island Area, South Louisiana

The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains some of our largest proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields.

The Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome, which we believe offer significant future opportunities for added production and reserves. During the first quarter of 2015 and in response to softening commodity prices, we released both the drilling and completion rigs and focused our efforts on maintaining production through more efficient lifting operations.We expect to continue development activity in this field in 2016.  As of December 31, 2015, we had a 96% average working interest in 36 gross producing wells, and had identified 6 PUD locations in this field.

The Cote Blanche Island field, located in St. Mary Parish, was acquired by Alta Mesa with an effective date of July 1, 2014.  The field is a salt dome structure and production from the Miocene sands was discovered in 1948 by Texaco, three years after the discovery at Weeks Island. The geology is similar to Weeks Island and we plan on utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that weuse at Weeks Island to increase reserves and production.  We own a 100% working interest with an average revenue interest of 83% in this field.

As of December 31, 2015, we had a 97% average working interest in a total of 41 gross producing wells, and had identified 8 PUD locations in the Weeks Island Area. We produced 1,686 MBOE net to us from the Weeks Island Area in 2015, a decrease of 8% as compared to 1,837 MBOE in 2014.  We have allocated approximately $10 million of our 2016 capital expenditure budget to the Weeks Island Area and plan to utilize at least oneworkover rig during 2016, as well as onedrilling rig for a portion of the year.

Other Assets

We conduct operations in other areas, including Urbana, Cold Springs and Cold Springs West in East Texas, Blackjack Creek oil field in Florida, and other fields in South Louisiana.  We continually evaluate the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans.  We have allocated approximately $10 million of our 2016 capital expenditure budget to these properties.

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Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2015:  

	As of December 31, 2015
	Oil
	and
	NGL's	Gas
	(MBbls)	(MMcf)
Proved Reserves (1)
Developed	21,900	71,753
Undeveloped	30,679	83,671
Total Proved	52,579	155,424

(1) Our proved reserves as of December 31, 2015 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. These average prices were $50.28 per Bbl for oil and $2.58 per MMBtu for natural gas. Pricing was adjusted for basis differentials by field based on our historical realized prices.  If commodity prices remain below the average prices used to estimate 2015 proved reserves, we would expect additional negative price-related reserves revisions in 2016, which could be significant. See “Note 19 — Supplemental Oil and Natural Gas Disclosures (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Prices for oil or natural gas continued to decline and are currently below the average calculated for 2015.  Sustained lower prices will cause the unweighted arithmetic averageto decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced and may necessitate future write-downs.

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and our peers, and in accordance the 2007 Petroleum Resources Management System sponsored and approved by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers.The reserve estimation process begins with our Corporate Planning and Reserves department, which gathers and analyzes much of the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by our land department.  Lease operating and capital expenses are provided by our accounting department and reviewed by the Corporate Planning and Reserves department.  Our Vice President of Corporate Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

· Over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves;

· Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Masters of Business Administration from Oklahoma City University in 1988;

· Registered Professional Engineer in Oklahoma.

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields.

We maintain internal controls including the following to ensure the reliability of reserves estimations:

· no employee’s compensation is tied to the amount of reserves booked;

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· we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;

· reserve estimates are made by experienced reservoir engineers or under their direct supervision;

· each quarter, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and all new proved undeveloped reserves additions.

Ryder Scott Company, L. P. (“Ryder Scott”), a third party engineering firm, audited 97% of our 2015 proved reserves.  The audit constituted 105% of our PV-10as estimated by us.  This high percentage of coverage is the result of properties “not reviewed” having a negative PV10 due to future abandonment liabilities and/or near term operating expenses that exceed income as a result of low commodity prices.  Many of these properties, by definition, do not have economic reserves and these reserves are, therefore, counted as zero in the total.

A copy of the audit letter issued by Ryder Scott is filed with this report as Exhibit 99.1. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Kevin Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin.  Mr. Gangluff is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

The audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Proved Undeveloped Reserves

At December 31, 2015, we had PUDs of 44.6 MMBOE, or approximately 57% of total proved reserves. The PUDs are primarily in Sooner Trend and Weeks Island Area.

Total PUDs at December 31, 2014 were 27.2 MMBOE, or 48% of our total proved reserves.  The following table reflects the changes in PUDs during 2015: 

	MBOE
Proved undeveloped reserves, December 31, 2014	27,158
Converted to proved developed	(3,526)
Proved undeveloped reserve extensions and discoveries	20,875
Proved undeveloped reserves acquired	—
Proved undeveloped reserves sold	(5,706)
Proved undeveloped reserve revisions	5,824
Proved undeveloped reserves, December 31, 2015	44,625

PUDs converted to proved developed reserves were primarily in Sooner Trend and Weeks Island Area.  Total expenditures for the PUDs converted to proved developed reserves were approximately $54.4 million.  Extensions and discoveries were primarily in our Sooner Trendand Weeks Island Area.  PUD reserves sold were from dispositions of our remaining interest in Eagleville field and non-core assets in South Texas.  In 2015, we had positive revisions of 10.1 MBOE, which were partially offset by negative price revisions of 4.3 MBOE. These reserves were moved out of the PUD reserve category in compliance with the SEC five year rule.  Estimated future development costs, including plugged and abandonment cost (“P&A”), for PUDs remaining are approximately $327 million at December 31, 2015.

Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time.  We will be required to remove our PUDs if we do not drill those reserves within the required five year time frame, unless specific circumstances justify a longer time.  All of our PUDs at December 31, 2015 are scheduled to be drilled within five years of the date they were initially recorded.Lower prices for oil

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and natural gas as seen in the recent decline may cause us in the future to forecast less capital to be available for development of our PUDs, which may cause us to decrease the amount of our PUDs we expect to develop within the five year time frame.  In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop, which would cause us to remove them from the proved undeveloped category.

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil, natural gas, and natural gas liquids for the periods indicated below.  The data below include the effects of the amounts we reclassified from natural gas volumes and revenues to natural gas liquids volumes and revenues for the year ended December 31, 2013.  See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations: Year Ended December 31, 2014 v. Year Ended December 31, 2013,  Natural gas liquids revenues for more detailed information.

	Year Ended December 31,
	2015		2014		2013
Net production:
Oil (MBbls)		4,203		3,770		2,897
Natural gas (MMcf)		11,900		14,449		16,664
Natural gas liquids (MBbls)		678		537		398
Total (MBOE)		6,865		6,715		6,072
Total (MMcfe)		41,187		40,290		36,434
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	47.54	$	92.27	$	102.81
Natural gas (per Mcf)		2.57		4.50		3.68
Natural gas liquids (per Bbl)		16.01		34.04		38.37
Combined (per BOE)		35.15		64.20		61.67
Average sales price per unit after hedging effects:
Oil (per Bbl)	$	67.73	$	93.38	$	100.67
Natural gas (per Mcf)		4.43		4.87		5.14
Natural gas liquids (per Bbl)		16.01		34.04		38.37
Combined (per BOE)		50.73		65.62		64.66
Average costs per BOE:
Lease and plant operating expense	$	10.45	$	10.99	$	11.60
Production and ad valorem taxes		2.20		4.20		4.34
Workover expense		0.95		1.33		2.25
Average costs per Mcfe:
Lease and plant operating expense	$	1.74	$	1.83	$	1.93
Production and ad valorem taxes		0.37		0.70		0.72
Workover expense		0.16		0.22		0.38

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The following table provides a summary of our production, average sales prices and average production costs for the Sooner Trend area, which contributes approximately 85% of our total proved reserves as of December 31, 2015.  The largest field in Sooner Trend contributes 15% or more of our total proved reserves as of December 31, 2015. 

	Year Ended December 31,
Sooner Trend	2015		2014		2013
Net production:
Oil (MBbls)		2,006		1,072		306
Natural gas (MMcf)		4,276		2,083		859
Natural gas liquids (MBbls)		499		316		124
Total (MBOE)		3,218		1,734		573
Total (MMcfe)		19,306		10,411		3,439
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	45.90	$	89.34	$	94.90
Natural gas (per Mcf)		2.51		4.34		3.71
Natural gas liquids (per Bbl)		16.74		34.09		38.20
Average production costs per BOE:
Lease and plant operating expense	$	6.89	$	8.22	$	14.27
Production and ad valorem taxes		0.58		1.45		3.62
Workover expense		0.78		1.49		3.62
Average production costs per Mcfe:
Lease and plant operating expense	$	1.15	$	1.37	$	2.39
Production and ad valorem taxes		0.10		0.24		0.60
Workover expense		0.13		0.25		0.60

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or natural gas at their current levels are below the average calculated for 2015, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price.

Delivery Commitments

As of December 31, 2015, we had no commitments to provide a fixed quantity of oil, natural gas or natural gas liquids.

Drilling Activity

The following table sets forth, for each of the three years ended December 31, 2015, 2014 and 2013, the number of net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

	Year Ended December 31,
	2015	2014	2013
Development wells (net):
Productive	34.6	46.6	37.4
Dry	2.0	0.1	3.5
Total development wells	36.6	46.7	40.9
Exploratory wells (net):
Productive	3.9	1.0	2.7
Dry	4.9	5.6	3.0
Total exploratory wells	8.8	6.6	5.7

As of December 31, 2015, we were drilling 12 gross (8.89 net) wells.

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Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2015:  

	December 31, 2015
	Gross	Net
Oil wells:
Sooner Trend	359	254.8
Weeks Island Area	39	37.9
Other	67	20.8
All properties	465	313.5
Natural gas wells
Sooner Trend	22	12.5
Weeks Island Area	2	1.8
Other	114	64.1
All properties	138	78.4

Of the total well count as of December 31, 2015, 4 gross wells (3.1 net) are multiple completions.     

Productive wells are producing wells, shut-in wells we deem capable of production, wells that are waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up.  A gross well is a well in which a working interest is owned.  The number of net wells represents the sum of fractional working interests the company owns in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2015, all of which is located in the United States:

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Property:
Sooner Trend	68,850	45,854	28,439	27,659	97,289	73,513
Weeks Island Area	10,145	10,139	2,219	2,219	12,364	12,358
Other	83,122	37,009	456,327	364,336	539,449	401,345
All properties	162,117	93,002	486,985	394,214	649,102	487,216

As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

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Undeveloped Acreage Expirations

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2015, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:

	2016		2017		2018
	Gross	Net	Gross	Net	Gross	Net
Property:
Sooner Trend	13,387	12,949	6,027	6,027	6,661	6,463
Weeks Island Area	—	—	1,824	1,824	395	395
Northwest	252,427	225,169	18,260	12,238	26,941	18,084
Other	24,858	13,739	3,146	1,999	19,673	10,955
All properties	290,672	251,857	29,257	22,088	53,670	35,897

Marketing and Customers

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

We sell the oil and natural gas from several properties we operate primarily under a contract with ARM Energy Management, LLC (“AEM”).  We are a  part owner of AEM at less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account.  AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee.  Sales to AEM commenced in June 2013.  The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015.  During the second half of 2013 and throughout 2014 and 2015, we sold the majority of our production from operated fields to AEM.  Production from non-operated fields, the most significant of which were our Eagleville field in South Texas, and our Hilltop natural gas field in East Texas prior to their sale, was marketed on our behalf by the operators of those properties.  Production from our interests in Eagleville was sold by the operator, Murphy Oil Corporation.  We sold our remaining interests in Eagleville in the third quarter of 2015.  See “Note 3 — Acquisitions and Divestitures” in the accompanying Notes to the Consolidated Financial Statements included elsewhere in this report for additional information.

Natural gas liquids are sold under various contracts with processors typically in the vicinity of the production at spot market rates, after processing costs.

For the year ended December 31, 2015, revenues from AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities.  Based on revenues excluding hedging activities, no other major customer accounted for 10% or more of revenues.

We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available.  Trade accounts receivable are not collateralized or otherwise secured.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects, and mineral leases and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and

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exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.

We compete for capital in the domestic financial marketplace to fund our exploration and development activities to the extent our operations cannot support them at any given time. See Item 1A, Risk Factors, “Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.”

Title to Properties

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Employees

As of December 31, 2015, we had 233 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1.8 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

Our offshore activities are limited to non-operator positions in five older fields acquired in 2010. Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields, and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability, and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.

We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be

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able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Environmental Matters and Regulation

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

· require the acquisition of various permits before drilling commences;

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

· place restrictions or regulations upon the use of the material based on our operations and upon the disposal of waste from our operations;

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

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

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

· require the expenditure of significant amounts in connection with worker health and safety.

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, Congress and federal, state and local 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. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters.  For example,theEPAhasidentifiedenvironmentalcompliancebytheenergyextractionsectorasoneofitsenforcementinitiativesfor2014-2016 and recently renewed this enforcement initiative for fiscal years 2017 to 2019.

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

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA and not all states similarly exempt oil and gas waste from hazardous waste regulation. Although a substantial amount of the waste generated in our operations is 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 or categorize some of our waste as hazardous 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.

Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”)

CERCLA imposes joint and several liability for costs of investigation and remediation and for natural resource damages 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 (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“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 found at a site where a release has occurred. CERCLA also authorizes 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.

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. Comparable state statutes may not provide a comparable exemption for petroleum. 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

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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 and in the past have owned, leased or operated 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 materials 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 materials disposed or released on them may be subject to CERCLA or RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (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 (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, 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 the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

Oil Pollution Act

The primary federal law related to oil spill liability is the Oil Pollution Act 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. 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 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.

Safe Drinking Water Act (“SDWA”)and Hydraulic Fracturing

Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In our Sooner Trendplay, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We also perform hydraulic fracturing in vertical wells in our East Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among the target zones are the Wilcox and Frio formations.

Currently, most hydraulic fracturing activities are regulated at the state level, as the Safe Drinking Water Act exempts most hydraulic fracturing (except for hydraulic fracturing activities involving the use of diesel) from the definition of underground injection. The EPA has commenced a wide-ranging study on the effects of hydraulic fracturing on drinking water resources and released a draft report in 2015.  The EPA had released guidance on permitting of hydraulic fracturing activities using diesel. Congress has periodically considered legislation to amend the federal SDWA to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing and to require the disclosure and reporting of the chemicals used in hydraulic fracturing. This type of legislation if adopted could lead to additional regulation and permitting requirements that could result in operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and operation.

As noted above, the EPA has announced that one of its enforcement initiatives through fiscal year 2019 is to focus on environmental compliance by the energy extraction sector. The hydraulic fracturing study and EPA’s focus on hydraulic fracturing, as well as the enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic

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fracturing and increase our costs of compliance and doing business. Consequently, this focus could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Many states and other regional and local regulatory authorities have enacted or are considering regulations on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit drilling in general or hydraulic fracturing in particular, in certain circumstances. Some states have also considered or adopted other restrictions or regulations on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations.  In compliance with the law enacted in Texas, we have disclosed and will continue to disclose hydraulic fracturing data. Further, the Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and has proposed pretreatment standards for discharges of wastewater generated by onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.

Finally, in some instances, including in Oklahoma, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect the Company, either directly or indirectly, depending on the wells affected.

If new legislation is enacted or other new requirements or restrictions regarding hydraulic fracturing are adopted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands (including offshore leasing) may be subject to the National Environmental Policy Act (the “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 and costs upon the development of oil and natural gas projects.

Air Emissions

Our operations are subject to local, state and federal regulations 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 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 require us to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions. Beginning January 1, 2015, operators now must capture the natural gas and make it available for use or sale. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emission from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We have evaluated the effect these rules will have on our business and are taking steps to ensure compliance.

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In 2015, the EPA proposed new rules limiting methane emissions from the oil and gas industry.  The proposed rules, if adopted, would amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. The EPA has also announced that it will begin to develop regulations for methane emissions from existing oil and gas sources.  

Simultaneously with the proposal of the methane rules, EPA released a proposal soliciting comments on two alternatives for aggregating multiple surface sites into a single-source of air quality permitting purposes.  Depending upon the alternative selected by EPA, sites which currently would not require permitting under the Clean Air Act could require permits, an outcome that could result in costs and delays to our operations; however, given the present uncertainty regarding this rule, the extent and magnitude of that impact cannot be reliably or accurately estimated.  In January 2016, BLM has proposed rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls and well as inspection requirements. 

Climate Change Regulation and Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“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 attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources and the planned development of methane regulations for existing oil and gas sources, both of which are discussed above.

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,  including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis.  Our operations are subject to GHG reporting requirements, and we continue to complywith such reporting requirements.  

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have expressed the intention to promote legislation to curb the EPA’s authority to regulate GHGs. In addition to possible federal regulation, a number of states, individually and regionallyas well as some localities, also are considering or have implemented GHG regulatory programsor other steps to reduce GHG emissions. These potential initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. 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.

Other Laws and Regulations

Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for our development.  We cannot guarantee that the U.S. Fish and Wildlife Service will not list additional species or additional habitat, which could adversely affect our ability to develop in impacted areas.

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OSHA and Other Laws and Regulation

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. 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 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. We believe that we are in substantial compliance with these applicable 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, 2015, 2014 and 2013. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2016 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot provide assurance 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.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

· the location of wells;

· the method of drilling, casing, and completing wells;

· the surface use and restoration of properties upon which wells are drilled; and

· the plugging and abandoning of wells.

State laws regulate the size and shape of drilling and spacing units or proration units and govern the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction and an ad valorem tax with respect to the assessed value of the oil and natural gas mineral property.

In addition, eleven states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate the surface owners/users for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

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We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the Bureau of Ocean Energy Management or other appropriate federal or state agencies.

Federal Regulation of Natural Gas, Oil and Natural Gas Liquids

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates.

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.  In October 2015, the PHMSA issued a Notice of Proposed Rulemaking proposing regulations to strengthen the way hazardous liquid pipelines in the U.S. are operated, inspected and maintained. Also, in March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing regulations to update critical safety requirements for natural gas transmission pipelines.

As an alternative to pipeline transportation, any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail will also be subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

The U.S. Department of Energy (“DOE”) regulates the export of natural gas produced in the U.S., including the export of liquefied natural gas (“LNG”), and the FERC regulates the construction and operation of liquefaction facilities used to convert gaseous natural gas into liquid for export as LNG. The DOE has granted several long-term LNG export licenses and FERC has authorized the construction and operation of several LNG export facilities for natural gas produced in the lower 48 states of the U.S., several of which are currently under construction. In March 2016, the first cargo of LNG from the lower 48 states of the U.S. is expected to be exported from an LNG export facility located in Louisiana.  It is too early to tell what impact this expansion of the markets available to natural gas produced in the U.S. will have on U.S. natural gas prices.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of oil, condensate, and natural gas liquids are not currently regulated and are made at market prices.

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State Natural Gas Regulation

Various states regulate the drilling for, and the production, gathering, intrastate transportation and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

General Corporate Information

Alta Mesa Holdings, LP is a Texas limited partnership founded in 1987 with principal offices at 15021 Katy Freeway, Suite 400, Houston, Texas 77094. We can be reached at (281) 530-0991 and our website address is www.altamesa.net. Information on the website is not part of this report.

Item 1A. Risk Factors

Each of the following risk factors could adversely affect our business, operating results and financial condition. It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. Our capital expenditures for 2015 totaled $238 million including $48 million for acquisitions. As a result of the continuing significant decline in oil prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2016 to approximately $115 million. We have funded development and operating activities primarily through equity capital raised from a private equity partner, through borrowings under our bank credit facility, through the issuance of our senior notes, and through internal operating cash flows. We intend to finance our future capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

· the estimated quantities of our proved oil and natural gas reserves;

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

· the prices at which we sell our production;

· take-away capacity; and

· our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.

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External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility 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 and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations.

Oil and natural gas prices are highly volatile and continued depressed prices can significantly affect our financial condition and results of operations.

Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and natural gas production are volatile and a decrease in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows.

Historically, world-wide oil and natural gas prices and markets have been subject to significant change, and may continue to be in the future. In particular, the prices of oil and natural gas declined dramatically in the second half of 2014 and throughout 2015.  For example, during 2015, based on daily settlements of monthly contracts traded on the NYMEX, the average price for a barrel (bbl) of oil ranged from a high of $105.15 for the June 2014 contract to a low of $37.33 for the December 2015 contract and the price for an MMBtu of natural gas ranged from a high of $5.56 for the February 2014 contract to a low of $2.03 for November 2015 contract.

Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves.  The average realized price, excluding hedge settlements, at which we sold oil in 2015 was $47.54 per barrel compared to $92.27 per barrel in 2014, and $102.81 per barrel in 2013. Because the oil price we are required to use to estimate our future net cash flows is the average price over the twelve months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters.  We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if prices increase.

Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

· the domestic and foreign supply of and demand for oil and natural gas;

· the price and quantity of foreign imports of oil and natural gas;

· recent changes in federal regulations removing decades-old prohibition of the export of crude oil production in the U.S.;  

· federal regulations applicable to exports of liquefied natural gas (LNG), including the recent export of the first quantities of LNG liquefied from natural gas produced in the lower 48 states of the U.S;

· the level of consumer product demand;

· weather conditions;

· domestic and foreign governmental regulations and taxation;

· overall domestic and global economic conditions;

· the value of the dollar relative to the currencies of other countries;

· political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

· the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

· the proximity and capacity of natural gas pipelines and other transportation facilities to our production;

· technological advances affecting energy consumption;

· the price and availability of alternative fuels; and

· the impact of energy conservation efforts.

Substantially all of our production is sold to purchasers under contracts with market-based prices. Continued lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves. If oil and natural gas prices remain at current levels, 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

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would require us to borrow to fund our 2016 capital budget. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas 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 and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Lower oil and natural gas prices may cause us to record non-cash write-downs, which could negatively impact our results of operations.

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. We recognized impairment expense during 2015 of $176.8 million as a result of lower forecasted commodity prices.  We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

We will depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.

Our estimated proved 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.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2015. The process of estimating oil and natural gas 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 and natural gas 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. 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 and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or natural gas at their current levels are currently below the average calculated for 2015, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.

The Standardized Measure of discounted future net cash flows from our proved reserves or “PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.

It should not be assumed that the Standardized Measure of future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding twelve months from the date of the report 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:

· actual prices we receive for crude oil and natural gas;

· actual cost of development and production expenditures;

· the amount and timing of actual production;

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· transportation and processing; and

· changes in governmental regulations or taxation.

Prices for oil or natural gas at their current levels are currently below the average calculated for 2015 and sustained lower prices will cause the unweighted arithmetic averageto decrease over time as the lower prices are reflected in the average price, which may reduce both in the estimated quantities and present values of our reserves and which may necessitate write-downs in the value of our oil and natural gas properties.

The timing of both our production and our incurrence of expenses in connection with the development and production of our 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 the Standardized Measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. If oil and natural gas prices decline by 10%, then the Standardized Measure as of December 31, 2015 would decrease approximately $127 million.

During 2015, the Company recognized significant impairments of proved oil and gas properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and changes to the Company’s drilling plans. At December 31, 2015, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $385.0 million indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $22.2 million. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.

Approximately 57% of our total estimated proved reserves at December 31, 2015 were proved undeveloped reserves requiring substantial capital expenditures and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2015, approximately 44.6 MMBOE of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2015 assumes that we will spend $327 million, including plugged and abandonment cost, to develop our estimated proved undeveloped reserves, including an estimated $52 million in 2016. Although cost and reserve estimates attributable to our natural gas and oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated proved undeveloped reserves over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, continued declines in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical.  As a result of depressed oil and natural gas prices, we have reduced the budgeted capital expenditures for the development of undeveloped reserves in 2016.  These delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

· the results of our drilling program;

· hydrocarbon prices;

· our ability to develop existing prospects;

· our ability to obtain leases or options on properties for which we have 3-D seismic data;

· our ability to acquire additional 3-D seismic data;

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· our ability to identify and acquire new exploratory prospects;

· our ability to continue to retain and attract skilled personnel;

· our ability to maintain or enter into new relationships with project partners and independent contractors; and

· our access to capital.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3-D seismic technology with respect to certain of our projects. The use of 2-D and 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.

We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.

The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot provide assurance that we will continue to maintain production levels through drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.  Additionally, in the current depressed oil price environment, we have reduced our capital expenditures for drilling in 2016.  As a result, we may not be able to increase or maintain production through our drilling activity.

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. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our partnership agreement, our senior secured revolving credit facility and the indenture governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our partnership agreement, our senior secured revolving credit facility, our senior secured term loan facility and the indenture governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.

Our business activities are subject to operational risks, including:

· damages to equipment caused by natural disasters such as earthquakes and adverse weather conditions, including tornadoes, hurricanes and flooding;

· facility or equipment malfunctions;

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· pipeline ruptures or spills;

· surface fluid spills, salt water contamination, and surface or groundwater contamination form petroleum constituents or hydraulic fracturing chemical additions;

· fires, blowouts, craterings and explosions; and

· uncontrollable flows of oil or natural gas or well fluids.

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our production. As of December 31, 2015, we have hedged approximately 72% of our total forecasted PDP production through 2019 at average annual floor prices ranging from $2.92 per MMBtu to $4.50 per MMBtu for natural gas and $62.50 per Bbl to $72.27 per Bbl for oil, with the majority of the hedged volumes in 2016. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future price declines will be dependent upon prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near-term estimated 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 commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in 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 substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

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.  This risk of counterparty non-performance is of particular concern given the disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and 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.  Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.

During periods of falling commodity prices our hedge receivable positions increase, which increases our 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 derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.  Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule regarding the capital a swap dealer or major swap participant is required to post with respect to its swap business, but has not yet issued a final rule. The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. 

In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a derivatives clearing organization and to trade all such swaps on an exchange.  The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.  All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.

While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current swap counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.  The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

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. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. 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 be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low commodity 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

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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. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, 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.

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

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s 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 will 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 before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.

We are vulnerable to risks associated with operating in the inland waters region of South Louisiana.

Our operations and financial results could be significantly impacted by unique conditions in the inland waters region of South Louisiana because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the inland waters region of South Louisiana, including those relating to:

· adverse weather conditions and natural disasters;

· availability of required performance bonds and insurance;

· oil field service costs and availability;

· compliance with environmental and other laws and regulations;

· new safety requirements, new regulations, increased costs of services and rig mobilizations, slowed issuance of permits for new wells and additional insurance costs and requirements;

· remediation and other costs resulting from oil spills or releases of hazardous materials; and

· failure of equipment or facilities.

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

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

· the Clean Air Act (“CAA”) and comparable state laws and regulations that impose obligations related to air emissions;

· the Clean Water Act and Oil Pollution Act (“OPA”) and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

· the Safe Drinking Water Act (“SDWA”) and comparable state laws and regulations that impose obligations on, among other things, the subsurface injection of materials;

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· the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

· the Comprehensive Environmental Response, Compensation, and Liability Act (“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;

· the Emergency Planning and Community Right to Know regulations under Title III of CERCLA and similar state statutes requiring that we organize and/or disclose information about hazardous materials used or produced in our operations; and

· the Endangered Species Act which may restrict or prohibit operations that could harm protected species or that would occur in a protected area.

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 RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change, greenhouse gases, and hydraulic fracturing, may be adopted in the future. 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 materials into the environment.

Our operations are substantially dependent on the availability of water.  Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes.  Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions, which could result in restrictions on water use.  If drought conditions were to occur, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.  If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions.  Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  The EPA has recently proposed rules to reduce methane emissions from new oil and gas operations and has announced its intention to regulate methane emissions from oil and gas operations.  Those measures may include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources.

EPA requires the reporting of GHG emissions from specified large GHG emission sources in the United States including from onshore and offshore oil and natural gas production, processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis.  Although both houses of Congress, in past sessions, have considered legislation to reduce emissions of GHGs, no comprehensive program has been enacted by Congress.  In the absence of a comprehensive federal program, many states, either individually or through multistate regional initiatives, and localities are considering or have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any statutes, regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretive guidance on climate change disclosure, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities and our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by

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disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas. Congress has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed. The SDWA does not exempt hydraulic fracturing activities using diesel. The EPA has developed guidance for permitting of hydraulic fracturing activities using diesel.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and issued draft report in 2015.  The Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  Additionally the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and is working on regulations for wastewater generated by hydraulic fracturing and has proposed pretreatment standards for discharges of wastewater generated by onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.

In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Any other new laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business.

Further, in April 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions. Beginning January 1, 2015, operators now must capture the natural gas and make it available for use or sale. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment.  Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Compliance with such regulations could require modifications to the operations of our natural gas exploration and production operations including the installation of new equipment, which could result in significant costs.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field 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. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.

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 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 and natural gas we may produce and sell.

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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 and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial position could be adversely affected.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

We have limited control over properties which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations, an operator’s financial difficulties, including as a result of the severe decline in oil and natural gas prices in 2014 and 2015, or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.

High Mesa, an affiliate of a private equity fund focused on energy and commodities, is the holder of our Class B limited partner interest. Under our partnership agreement, the Class B limited partner has certain significant rights, including, without limitation:

· approval of material sales and acquisitions of properties and assets, the incurrence of debt, the appointment of any successor to our Chief Executive Officer and any other senior officers; the entering into of partnerships and joint ventures; our merger or consolidation with any entity; and the issuance of interests, ownership interests, debentures, bonds and other securities of the company;

· approval of our annual development plan and budget;

· approval of modifications to our policies or procedures to mitigate our commodity price risks;

· the right to part of the proceeds of any future debt or equity offering; and

· the right, in certain circumstances, to cause our partners to sell their units or to cause us to sell our assets in a liquidity event.

The interests of the Class B limited partner could conflict with the interests of our other investors, such as the holders of our senior notes. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Class B limited partner may conflict with the interests of the holders of our senior notes. The Class B limited partner also may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to our other investors.

We may not be able to repurchase our outstanding senior notes upon a change of control.

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, we will be required to offer to repurchase all of our outstanding notes at 101% of the principal amount of such senior notes plus accrued and unpaid interest to the date of repurchase. We may not have available funds sufficient to pay the change of control purchase price for any or all of the senior notes that might be tendered in the change of control offer.

The definition of change of control in the indenture governing the senior notes includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of our and our restricted subsidiaries’ assets, taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of senior notes to require us to repurchase such senior notes as a result of a sale, transfer, conveyance or other disposition of “less than all of our and our restricted subsidiaries” assets taken as a whole to another person or group may be uncertain. Our limited partnership agreement permits High Mesa to cause our general partner to initiate a sale of our company to a third-party, which sale may be deemed to be a change of control. High Mesa may exercise this right at a time that we do not have sufficient capital or are otherwise prohibited from repurchasing the senior notes. In addition, our senior secured revolving credit facility contains, and any future credit agreement likely will contain, restrictions or prohibitions on our ability to repurchase the senior notes under certain circumstances. If these change of control events occur at a time when we are prohibited from repurchasing the senior notes, we may seek the consent of our lenders to purchase the senior notes or could attempt to refinance the borrowings that contain these prohibitions or restrictions. If we do not obtain our lenders’ consent or refinance these borrowings, we will not be able to repurchase the senior notes. Accordingly, the holders of the senior notes may not receive the change of control purchase price for their notes in the event of a sale or other change of control, which will give the trustee and the holders of the senior notes the right to declare an event of default and accelerate the repayment of the senior notes.

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Our private equity partner and its affiliates are not limited in their ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement with our private equity partner does not prohibit it or its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, our private equity partner and its affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Highbridge is part of a larger family of funds, which has significantly greater resources than we have, which may make it more difficult for us to compete for acquisition candidates if our private equity partner or its affiliates were to compete against us.

We depend on key personnel, the loss of any of whom could materially adversely affect future 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 key-man life insurance with respect to any of our employees. 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.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements.  Additionally, new fields may require the construction of gathering systems and other transportation facilities.  These facilities may require us to spend significant capital that would otherwise be spent on drilling.  Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.  Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.  The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

Historically, we have been dependent upon a few customers for a significant portion of our revenue. To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues could decline.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our senior secured revolving credit facility, the senior secured term loan facility, and the indenture for the senior notes contain restrictive covenants that limit our ability to, among other things:

· incur or guarantee additional debt;

· make distributions;

· repay subordinated debt prior to its maturity;

· grant additional liens on our assets;

· enter into transactions with our affiliates;

· enter into hedging transactions with non-lender hedge counterparties;

· repurchase equity securities;

· make certain investments or acquisitions of substantially all or a portion of another entity’s business assets; and

· merge with another entity or dispose of any material assets.

In addition, our senior secured revolving credit facility and senior secured term loan facility requires us to maintain certain financial ratios and tests, such as leverage ratios. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain

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future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.  As of December 31, 2015, we were in compliance with all of the financial covenants under our credit facility and senior secured term loan facility. Failure to maintain these covenants could preclude us from borrowing under our revolving credit facility and require us to immediately pay down any outstanding drawn amounts under the credit agreement, which could affect cash flows or restrict business.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our revolving credit facility is currently subject to a borrowing base of $300 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility.  As of December 31, 2015, we had outstanding borrowings of $152 million. We intend to continue borrowing under our revolving credit facility in the future as needed. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. Any default under these agreements governing our indebtedness that is not waived by the required lenders or holders, as the case may be, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our senior secured revolving credit facility and the indenture governing the senior notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our credit facility could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

Our borrowings under our senior secured revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility. Our senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. We may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

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To service our indebtedness, we require a significant amount of cash, and our ability to generate cash will depend on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, and to fund planned capital expenditures depends in part on our ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot provide assurance that we will generate sufficient cash flow from operations, that we will realize operating improvements on schedule, or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

· refinancing or restructuring our debt;

· selling assets;

· reducing or delaying capital investments; or

· seeking to raise additional capital.

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations.

We cannot provide assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations, including our obligations under the senior notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Future disruptions in the global credit markets may make equity and debt markets less accessible, create a shortage in the availability of credit, and lead to credit market volatility that could limit our ability to grow.

The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Continuing concerns regarding the worldwide economic outlook and sovereign debt crisis in Europe have contributed to increased economic uncertainty and diminished expectations for the global economy. A slowdown in the current economic recovery or a return to a recession would negatively impact demand for petroleum products and prices for natural gas and oil. Disruptions in the capital and credit markets, as was experienced during 2008 and 2009, could adversely affect our ability to meet our liquidity needs or to refinance our indebtedness, including our ability to draw on our existing credit facility or enter into new credit facilities.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant

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additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Information regarding our properties is contained in “Item 1. Business” contained herein.

Item 3. Legal Proceedings

We are party to various litigation matters arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our consolidated financial statements. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff sought damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleged damages from increased costs of providing man-made storm protection structures, and emphasized the destructive effect of canals built by the oil and gas industry.  Legal arguments included breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments included negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource Company, LLC was named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive.  In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  It is possible that the constitutionality of Act 544 may be litigated.

On February 13, 2015, the case was dismissed by the U.S. District Judge.  As of December 31, 2015, we have not provided any amount for this matter in our consolidated financial statements.

Environmental claims:  Various landowners have sued our wholly owned subsidiary The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, in lawsuits concerning several fields in which Meridian has historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at December 31, 2015.  

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management has established a liability for soil contamination in Florida of $1.3 million at December 31, 2015 and $1.1 million at December 31, 2014, based on our undiscounted engineering estimates.  The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.  No accrual for environmental claims has been made other than the balance noted above.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

No class of our limited partnership interests has been registered under the Exchange Act, and there is no established public trading market for our equity.

As of March 29, 2016, four holders of our limited partnership interests held 100% of such interests.

Distributions to our partners are determined by the terms of our partnership agreement.  See also, “Risk Factors — High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.” We are also currently

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restricted in our ability to pay dividends under our senior secured revolving credit facility. Historically, limited distributions have been made with the approval of our Board of Directors.

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Item 6. Selected Financial Data

The following table presents our selected financial data for the periods indicated. The data have been derived from our audited consolidated financial statements for such periods. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this report.  The following information is not necessarily indicative of our future results.

	Year Ended December 31,
	2015		2014		2013		2012		2011
	(in thousands)
Statement of Operations Data:
Revenues:
Oil, natural gas, and natural gas liquids	$	241,284	$	431,125	$	374,450	$	294,981	$	302,460
Other revenue		682		1,003		1,207		4,567		2,127
Total operating revenues		241,966		432,128		375,657		299,548		304,587
Gain (loss) on sale of assets		67,781		87,520		(2,715)		—		—
Gain (loss) on derivative contracts		124,141		96,559		(17,150)		19,751		49,620
Total operating revenues and other		433,888		616,207		355,792		319,299		354,207
Expenses:
Lease and plant operating expense		71,736		73,820		70,450		69,047		62,637
Production and ad valorem taxes		15,131		28,214		26,369		23,485		19,357
Workover expense		6,511		8,961		13,679		12,740		11,777
Exploration expense		42,718		61,912		33,065		21,912		15,785
Depreciation, depletion, and amortization		143,969		141,804		118,558		109,252		94,251
Impairment expense		176,774		74,927		143,166		96,227		18,735
Accretion expense		2,076		2,198		2,133		1,813		1,812
General and administrative expense		44,454		69,198		47,023		40,222		33,087
Total operating expenses		503,369		461,034		454,443		374,698		257,441
Income (loss) from operations		(69,481)		155,173		(98,651)		(55,399)		96,766
Other income (expense):
Interest expense, net		(61,750)		(55,797)		(55,064)		(41,833)		(32,644)
Litigation settlement		—		—		—		1,250		—
Gain on contract settlement		—		—		—		—		1,285
Total other expense		(61,750)		(55,797)		(55,064)		(40,583)		(31,359)
(Provision) benefit for state income taxes		(562)		(176)		—		107		(228)
Net income (loss)	$	(131,793)	$	99,200	$	(153,715)	$	(95,875)	$	65,179
Statement of Cash Flow Data:
Capital expenditures	$	223,604	$	366,090	$	311,438	$	224,719	$	193,770
Net cash flow provided by operating activities		143,978		184,884		172,519		147,193		150,655
Net cash used in investing activities		(105,815)		(189,721)		(336,147)		(255,065)		(266,133)
Net cash provided by (used in) financing activities		(30,643)		(351)		164,379		111,028		113,272
Balance Sheet Data (at period end):
Cash and cash equivalents	$	8,869	$	1,349	$	6,537	$	5,786	$	2,630
Property and equipment, net		537,039		697,681		700,870		655,497		589,167
Total assets (1)		722,525		911,125		785,300		772,522		712,041
Total debt, including Founder Notes (1)		743,523		785,682		782,008		614,071		499,905
Total partners' capital (deficit)		(177,049)		(61,446)		(160,107)		(6,368)		89,672

(1) Prior to 2015, we presented deferred financing costs related to our senior unsecured notes and senior secured term loan facility in deferred financing costs, net on our consolidated balance sheets. Upon the adoption of new accounting guidance in 2015, such costs are presented as a deduction from the carrying value of long-term debt. As of December 31, 2015, deferred financing costs related to our senior unsecured notes and senior secured term loan facility totaling $7.8 million were included in long-term debt on our consolidated balance sheet. Prior periods have been adjusted retrospectively to reflect the period-specific effects of applying the new guidance. Reclassified amounts total $6.4 million, $8.2 million, $9.9 million and $8.0 million for the years ended December 31, 2014, 2013, 2012 and 2011, respectively.

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

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987.  Currently, we are focusing our drilling efforts in our core properties in the Sooner Trend area of the Anadarko Basin in Oklahoma and the Weeks Island Area in South Louisiana.  We maintain operational control of the majority of our properties, either through directly operating them, or through operating arrangements with minority interest holders.  Our operations also include other oil and natural gas interests in Texas and Louisiana.

The amount of revenue we generate from our operations will fluctuate based on, among other things:

· the prices at which we will sell our production;

· the amount of oil and natural gas we produce; and

· the level of our operating and administrative costs.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our consolidated results of operations in the future.

Outlook

The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years.  Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil.  Oil prices are subject to significant changes.  Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years.  Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, Ukraine, and South America, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets.  Sustained low oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and the amount of our borrowing base under our credit facility.

Oil prices for West Texas Intermediate traded on the NYMEX (“NYMEX WTI”) averaged approximately $93.00 per Bbl in 2014 as compared to an average price of $48.79 per Bbl in 2015.  NYMEX WTI futures reached a high average price of $59.82 per Bbl in June 2015and closed at an average price of $37.32 per Bbl in December 2015. 

Natural gas prices for NYMEX Henry Hub averaged approximately $4.42 per MMBtu in 2014 as compared to an average price of $2.66 per MMBtu in 2015.  NYMEX Henry Hub futures reached a high price of $5.56 per MMBtu in February 2014 and closed at a price of $2.21 per MMBtu in December 2015.

Depressed oil and natural gas prices have impacted our earnings by necessitating impairment write-downs in some of our  properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs.  We recorded non-cash impairment expenses of $176.8 million and $74.9 million during the years ended December 31, 2015 and 2014, respectively.  The 2015 write-downs were primarily due to downward revisions in proved reserves in some fields and decreased prices for oil, natural gas and natural gas liquids.  Our impairments were primarily related to our Weeks Island Area, Oklahoma, and non-core assets.  For further information, see “Results of Operations: Year Ended December 31, 2015 v. Year Ended December 31, 2014:  Impairment Expense.”

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Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved.  At December 31, 2015, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $385.0 million indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $22.2 million. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2016. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

Our derivative contracts are reported at fair value on our consolidated balance sheets and are highly sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as gain / loss on derivative contracts which include both the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In 2015, we recognized a net gain on our derivative contracts of $124.1 million, which includes $106.9 million in cash settlements received for derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

We have hedged approximately 72% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $2.92 per MMBtu to $4.50 per MMBtu for natural gas and $62.50 per Bbl to $72.27 per Bbl for oil.  If oil and/or natural gas prices continue to decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices.

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

Recent Developments and Acquisition and Divestiture Activity

Drillco Contract

On January 13, 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement with BCE, to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches.

Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each Joint Well, provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well.

On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million.  The terms and conditions are the same as those of the first two tranches aforementioned.

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Kingfisher Acquisition

On July 6, 2015, we acquired approximately 19,000 net acres of undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and is subject to customary purchase price adjustments. The effective date of the acquisition is April 1, 2015. The purchase was funded with borrowings under our credit facility.

Alta Mesa Eagle, LLC Divestiture

On September 30, 2015, we closed the sale of all the membership interests in AME that held all of our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement dated September 16, 2015 (the “Eagle Ford divestiture”). The effective date of the transaction was July 1, 2015.

Pursuant to the agreement, the aggregate cash sale price was $125 million, subject to certain adjustments, consisting of a $118 million initial payment paid at closing, and additional contingent payments of approximately $7 million in the aggregate. As of December 31, 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million.  Cash received was utilized to pay down borrowings under our credit facility.  

As of July 1, 2015, the estimated net proved reserves sold were approximately 7.8 MMBOE. As a result of the Eagle Ford divestiture, we no longer own any assets in the Eagle Ford shale play.

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Results of Operations: Year Ended December 31, 2015 v. Year Ended December 31, 2014

	Year Ended December 31,				Increase
	2015		2014		(Decrease)		% Change
	(in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		4,203		3,770		433	11%
Natural gas (MMcf)		11,900		14,449		(2,549)	(18)%
Natural gas liquids (MBbls)		678		537		141	26%
Total oil equivalent (MBOE)		6,865		6,715		150	2%
Average daily oil production (MBOE per day)		18.8		18.4		0.4	2%
Average Sales Price:
Oil (per Bbl) realized	$	67.73	$	93.38	$	(25.65)	(27)%
Oil (per Bbl) unhedged		47.54		92.27		(44.73)	(48)%
Natural gas (per Mcf) realized		4.43		4.87		(0.44)	(9)%
Natural gas (per Mcf) unhedged		2.57		4.50		(1.93)	(43)%
Natural gas liquids (per Bbl) realized (1)		16.01		34.04		(18.03)	(53)%
Combined (per BOE) realized		50.73		65.62		(14.89)	(23)%
Hedging Activities:
Settlements of derivatives received, oil	$	84,856	$	4,187	$	80,669	1927%
Settlements of derivatives received, natural gas		22,093		5,306		16,787	316%
Summary Financial Information
Revenues
Oil	$	199,799	$	347,842	$	(148,043)	(43)%
Natural gas		30,621		65,002		(34,381)	(53)%
Natural gas liquids		10,864		18,281		(7,417)	(41)%
Other revenues		682		1,003		(321)	(32)%
Gain on sale of assets		67,781		87,520		(19,739)	(23)%
Gain on derivative contracts		124,141		96,559		27,582	29%
Total Operating Revenues and Other		433,888		616,207		(182,319)	(30)%
Expenses
Lease and plant operating expense		71,736		73,820		(2,084)	(3)%
Production and ad valorem taxes		15,131		28,214		(13,083)	(46)%
Workover expense		6,511		8,961		(2,450)	(27)%
Exploration expense		42,718		61,912		(19,194)	(31)%
Depreciation, depletion, and amortization expense		143,969		141,804		2,165	2%
Impairment expense		176,774		74,927		101,847	136%
Accretion expense		2,076		2,198		(122)	(6)%
General and administrative expense		44,454		69,198		(24,744)	(36)%
Interest expense, net		61,750		55,797		5,953	11%
Provision for state income taxes		562		176		386	219%
Net Income (loss)	$	(131,793)	$	99,200	$	(230,993)	(233)%
Average Unit Costs per BOE:
Lease and plant operating expense	$	10.45	$	10.99	$	(0.54)	(5)%
Production and ad valorem tax expense		2.20		4.20		(2.00)	(48)%
Workover expense		0.95		1.33		(0.38)	(29)%
Exploration expense		6.22		9.22		(3.00)	(33)%
Depreciation, depletion and amortization expense		20.97		21.12		(0.15)	(1)%
General and administrative expense		6.48		10.30		(3.82)	(37)%

(1) We entered into derivative contracts for natural gas liquids in the fourth quarter of 2015.  The derivative contracts for natural gas liquids are effective starting in 2016.  

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Revenues

Oil revenues for the year ended December 31, 2015 decreased $148.0 million, or 43%, to $199.8 million from $347.8 million for 2014. The decrease in revenue was attributable tolower average prices partially offset byincreased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 48% in 2015; the overall price including settlements of derivative contracts decreased 27% from $93.38 per Bbl in 2014 to $67.73 per Bbl in 2015 resulting in a decrease in oil revenues of approximately $188.0 million, partially offset by an increase in production of 433 MBbls, or 11% resulting in an approximately $40.0 million increase in oil revenues. This increase is primarily due to new production from our Sooner Trend field, which increased 934 MBbls, from 1,072 MBbls in 2014 to 2,006 MBbls in 2015, partially offset by lower sales volume due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and natural production decline at Weeks Island Area.  Production from our Eagleville field decreased 383 MBbls from 815 MBbls in 2014 to 432 MBbls in 2015, and our Weeks Island Area decreased 61 MBbls from 1,505 MBbls in 2014 to 1,444 MBbls in 2015.  

Natural gas revenues for the year ended December 31, 2015 decreased $34.4 million, or 53%, to $30.6 million from $65 million for 2014. The decrease in natural gas revenue was attributable to lower average prices during 2015 as well as decreased production volumes.  The average price of natural gas exclusive of settlements of derivative contracts decreased 43% in 2015 resulting in a decrease in natural gas revenues of approximately $22.9 million.  The overall price including settlements of derivative contracts decreased 9% from $4.87 per Mcf in 2014 to $4.43 per Mcf in 2015.  A decrease in production of 2.5 Bcf, or 18% resulted in a decrease in natural gas revenues of approximately $11.5 million in 2015 compared to 2014.  The decline is due to an emphasis on liquids-rich assets in our capital spending. The decrease in production is attributable to the sale of our remaining working interests in the Hilltop field in the third quarter of 2014.  The Hilltop field produced 2.8 Bcf in 2014.  In addition, production decreased 3.8 Bcf in East Texas and 0.6 Bcf in South Texas, partially offset by an increase in production in our Sooner Trend field of 2.2 Bcf.

Natural gas liquids revenues decreased during 2015 to $10.9 million from $18.3 million for 2014.  Our average price decreased by 53%, from $34.04 per Bbl in 2014 to $16.01 per Bbl in 2015, partially offset by a 26% increase in volumes from 537 MBbls in 2014 to 678 MBbls in 2015.  The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling.The increase in volume is due primarily to an increase in production in the Sooner Trend field during 2015 of 184 MBbls, partially offset by lower sales volumes due to the sale of the remainder of our Eagleville properties in the third quarter of 2015.

Other revenues were $0.7 million during 2015 as compared to $1.0 million during 2014. The decrease is partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.

Gain on sale of assets was a gain of $67.8 million in 2015 as compared to a gain of $87.5 million in 2014.  The divestiture of our remaining Eagleville properties in 2015 resulted in a gain of $67.6 million.  The divestiture of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and $15.9 million, respectively.

Gain on derivative contracts was a gain of $124.1 million for 2015 as compared to a gain of $96.6 million for 2014. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expense decreased $2.1 million to $71.7 million in 2015 as compared to $73.8 million in 2014. On a per unit basis, lease and plant operating expense decreased 5% from $10.99 to $10.45 per BOE for 2014 and 2015, respectively.  The decrease is primarily due to lower expenses of chemical and fuel usage, salt water disposal, and marketing and gathering, totaling $8.8 million.  The decrease was partially offset by an increase in repairs and maintenance, compression and field services of $6.9 million.

Production and ad valorem taxes decreased $13.1 million to $15.1 million, or 46%, for 2015, as compared to $28.2 million for 2014.  Production taxes decreased $11.6 million primarily due to the decrease in oil and natural gas revenues.  Ad valorem taxes decreased $1.5 million primarily due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and the sale of our Hilltop field in the third quarter of 2014.  On a per unit basis, the production and ad valorem taxes decreased 48% from $4.20 to $2.20 per BOE for 2014 and 2015, respectively.

Workover expense decreased $2.5 million to $6.5 million from $9.0 million for 2015 and 2014, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $19.2 million to $42.7 million for 2015 from $61.9 million for 2014. The decrease in exploration expense is primarily due to decreases in G&G seismic expenditures of $11.7 million, dry hole expense of $7.6 million and plug and abandonment expenditures of $2.2 million, partially offset by an increase in delay rentals and expired leasehold

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of $2.2 million. As of December 31, 2015, our property, plant, and equipment balance includes $6.0 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes. 

Depreciation, depletion and amortization increased $2.2 million to $144.0 million for 2015 as compared to an expense of $141.8 million for 2014. On a per unit basis, this expense decreased 1% from $21.12 to $20.97 per BOE for 2014 and 2015, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased  $101.9 million to $176.8 million in 2015 from $74.9 million in 2014. This non-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. The increase in impairment expense is primarily due to a 47% decrease in the twelve month weighted average price for oil and a 41% decrease in the twelve month weighted average price for natural gas at December 31, 2015.  The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields.  The primary prospects impaired were in South Texas of approximately $4.1 million and Weeks Island Area of approximately $0.6 million. Several developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations.  The most significant of these were in Weeks Island Area of $129.1 million, Sooner Trend of $15.7 million, South Louisiana of $9.4 million and East Texas of $8.9 million.

Accretion expense is related to our obligation for retirement of oil and natural 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. Accretion expense was $2.1 million and $2.2 million in 2015 and 2014, respectively.

General and administrative expense decreased $24.7 million to $44.5 million in 2015 from $69.2 million in 2014. The decrease is primarily due to non-recurring capital restructuring expenditures of $13.9 million in 2014, as well as a bonus accrual reduction of $9.9 million and a decrease in deferred compensation expense of $1.8 million in 2015.  This decrease was partially offset by an increase in accrued settlement expense of $2.6 million.  On a per unit basis, general and administrative expenses decreased 37% from $10.30 to $6.48 per BOE for 2014 and 2015, respectively.

Interest expense, net increased $6.0 million to $61.8 million in 2015 from $55.8 million in 2014.  This increase is primarily due to incurred interest expense of $6.2 million and amortization of deferred financing costs of $0.5 million, related to the senior secured term loan facility that we entered into during 2015.  The increase in interest expense was partially offset by an increase in interest income of $0.7 million and lower interest expense of $0.1 million on our credit facility due to a lower average balance outstanding. 

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Results of Operations: Year Ended December 31, 2014 v. Year Ended December 31, 2013

	Year Ended December 31,				Increase
	2014		2013		(Decrease)		% Change
	(in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		3,770		2,897		873	30%
Natural gas (MMcf)		14,449		16,664		(2,215)	(13)%
Natural gas liquids (MBbls)		537		398		139	35%
Total oil equivalent (MBOE)		6,715		6,072		643	11%
Average daily oil production (MBOE per day)		18.4		16.6		1.8	11%
Average Sales Price:
Oil (per Bbl) realized	$	93.38	$	100.67	$	(7.29)	(7)%
Oil (per Bbl) unhedged		92.27		102.81		(10.54)	(10)%
Natural gas (per Mcf) realized		4.87		5.14		(0.27)	(5)%
Natural gas (per Mcf) unhedged		4.50		3.68		0.82	22%
Natural gas liquids (per Bbl) realized (1)		34.04		38.37		(4.33)	(11)%
Combined (per BOE) realized		65.62		64.66		0.96	1%
Hedging Activities:
Settlements of derivatives received (paid), oil	$	4,187	$	(6,193)	$	10,380	168%
Settlements of derivatives received, natural gas		5,307		24,370		(19,063)	(78)%
Summary Financial Information
Revenues
Oil	$	347,842	$	297,836	$	50,006	17%
Natural gas		65,002		61,350		3,652	6%
Natural gas liquids		18,281		15,264		3,017	20%
Other revenues		1,003		1,207		(204)	(17)%
Gain (loss) on sale of assets		87,520		(2,715)		90,235	3324%
Gain (loss) on derivative contracts		96,559		(17,150)		113,709	663%
Total Operating Revenues and Other		616,207		355,792		260,415	73%
Expenses
Lease and plant operating expense		73,820		70,450		3,370	5%
Production and ad valorem taxes		28,214		26,369		1,845	7%
Workover expense		8,961		13,679		(4,718)	(34)%
Exploration expense		61,912		33,065		28,847	87%
Depreciation, depletion, and amortization expense		141,804		118,558		23,246	20%
Impairment expense		74,927		143,166		(68,239)	(48)%
Accretion expense		2,198		2,133		65	3%
General and administrative expense		69,198		47,023		22,175	47%
Interest expense, net		55,797		55,064		733	1%
Provision (benefit) for state income taxes		176		—		176	NA
Net income (loss)	$	99,200	$	(153,715)	$	252,915	165%
Average Unit Costs per BOE:
Lease and plant operating expense	$	10.99	$	11.60	$	(0.61)	(5)%
Production and ad valorem tax expense		4.20		4.34		(0.14)	(3)%
Workover expense		1.33		2.25		(0.92)	(41)%
Exploration expense		9.22		5.45		3.77	69%
Depreciation, depletion and amortization expense		21.12		19.53		1.59	8%
General and administrative expense		10.30		7.74		2.56	33%

(1) We did not utilize hedging for natural gas liquids in 2014 or 2013.  

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Revenues

Oil revenues for the year ended December 31, 2014 increased $50.0 million, or 17%, to $347.8 million from $297.8 million for 2013. The increase in revenue was attributable to increased production volumes partially offset by lower average prices. Approximately $89.8 million of the increase in oil revenues for 2014 was due to an increase in production of 873 MBbls, or 30% over the same period for 2013. This increase is primarily due to new production from our Sooner Trend field, which increased 766 MBbls, from 306 MBbls in 2013 to 1,072 MBbls in 2014, and to our Weeks Island field, which increased production by 441 MBbls, from 1,053 MBbls in 2013 to 1,494 MBbls in 2014.  The average price of oil exclusive of settlements of derivative contracts decreased 10% in 2014; the overall price including settlements of derivative contracts decreased 7% from $100.67 per Bbl in 2013 to $93.38 per Bbl in 2014 resulting in a decrease in oil revenues of approximately $39.8 million.

For the years ended December 31, 2014, 2013 and 2012, we revised our reporting for oil, gas and natural gas liquids revenues.  Formerly, we reported all revenues “net” of realized gains and losses on related hedging activities, while we reported unrealized gains and losses on a separate revenue line item on the consolidated statements of operations. We are now reporting oil, gas and natural gas liquids revenues at “gross,” which does not include the effects of related hedging activities. Realized and unrealized gains and losses on related hedging activities are now recorded together on a separate revenue line item on the consolidated statements of operations. This change had no effect on our income (loss) from operations or net income (loss) for the periods stated.

Natural gas revenues for the year ended December 31, 2014 increased $3.7 million, or 6%, to $65.0 million from $61.3 million for 2013. The increase in natural gas revenue was attributable to higher average prices during 2014 partially offset by decreased production volumes.  The average price of natural gas exclusive of settlements of derivative contracts increased 22% in 2014 resulting in an increase in natural gas revenues of approximately $11.8 million.  The overall price including settlements of derivative contracts, decreased 5% from $5.14 per Mcf in 2013 to $4.87 per Mcf in 2014.  This was partially offset by approximately $8.1 million due to a decrease in production of 2.2 Bcf, or 13%. The decline is due to an emphasis on liquids-rich assets in our capital spending. Hilltop field, our largest natural gas field in 2013, produced 2.8 Bcf in 2014, compared to 5.8 Bcf in 2013.  We curtailed capital expenditures in the field in both 2013 and 2014, leading to production declines unmitigated by new production.   In addition, we sold a substantial portion of our working interest in the field, comprising proved reserves of approximately 11.2 BCFE, in October 2013, and the remaining working interests in the field in the third quarter of 2014.  

Natural gas liquids revenues increased during 2014 to $18.3 million from $15.3 million for 2013. A 35% increase in volumes from 398 MBbls in 2013 to 537 MBbls in 2014 was partially offset by a decrease in our average price of 11%, from $38.37 per Bbl in 2013 to $34.04 per Bbl in 2014. The increase in volume is due primarily to an increase in production in the Sooner Trend field during 2014 of 192 MBbls.  The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling.

In 2013, we revised our reporting for natural gas liquids produced in our Oklahoma properties.  Whereas we had previously reported all volumes and revenues for 2012 as attributable to a single stream of rich natural gas, we began recording revenues for natural gas liquids from Oklahoma separately in 2013.  For comparability, we reclassified approximately $3.3 million in revenues from natural gas to natural gas liquids for the year 2012.  The related volumetric reclassification included a reduction of 397 MMcf of natural gas produced, and an addition of 92 MBbls of natural gas liquids produced for the year 2012.  These reclassifications had no impact on previously reported total revenues, net income (loss), cash flows, or partners’ capital (deficit).  The analysis of the increase in revenues from 2012 to 2013 included herein is based on the figures for each year after reclassifications.

Other revenues were $1.0 million during 2014 as compared to $1.2 million during 2013. The decrease is partially the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013.

Gain (loss) on sale of assets was a gain of $87.5 million in 2014 as compared to a loss of $2.7 million in 2013.  The divestiture of a portion of our oil and gas properties in Eagleville Field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and 15.9 million, respectively.  The loss on sale of assets of $2.7 million in 2013 was primarily related to the sale of a single well in South Texas and to the sale of our drilling rig. 

Gain (loss) on derivative contracts was a gain of $96.6 million for 2014 as compared to a loss of $17.2 million for 2013. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices, changes in our outstanding hedging contracts during these periods, and revisions to our presentation of oil, gas and natural gas liquids revenues for 2014 and 2013. 

Expenses

Lease and plant operating expense increased $3.4 million to $73.8 million in 2014 as compared to $70.4 million in 2013. On a per unit basis, lease and plant operating expense decreased 5% from $11.60 to $10.99 per BOE for 2013 and 2014, respectively. In general, lease operating expenses are higher for liquids-rich properties. Oil as a percentage of production on an equivalent basis increased from 48% in 2013 to 56% in 2014. Natural gas as a percentage of equivalent production during the same periods decreased from 46% to 36%. Components of the expense that reflected increases included chemical and fuel usage, salt water disposal,

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compression and marketing and gathering, totaling $ 5.8 million.  The increase was partially offset by a decrease in repairs, maintenance and field services of $2.9 million.

Production and ad valorem taxes increased $1.8 million to $28.2 million, or 7%, for 2014, as compared to $26.4 million for 2013.  Production taxes increased $ 1.9 million.  Ad valorem taxes decreased $ 0.1 million. On a per unit basis, the production and ad valorem taxes decreased 3% from $4.34 to $4.20 per BOE for 2013 and 2014, respectively.

Workover expense decreased $4.7 million to $9.0 million from $13.7 million for 2014 and 2013, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $28.8 million to $61.9 million for 2014 from $33.1 million for 2013. The majority of the 2014 activity was due to $30.3 million in dry hole costs, primarily related to dry holes in New Mexico, South Louisiana, and South Texas; and $23.2 million in G&G seismic costs, primarily in Sooner Trend and South Louisiana; and delay rentals and expired lease expense of $6.1 million. As of December 31, 2014, our property, plant, and equipment balance includes $13.3 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.  Alternatively, some costs may be charged to impairment expense if the fair value of proved reserves discovered is less than the capitalized cost.

Depreciation, depletion and amortization increased $23.2 million to $141.8 million for 2014 as compared to an expense of $118.6 million for 2013. On a per unit basis, this expense increased 8% from $19.53 to $21.12 per BOE for 2013 and 2014, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased $68.3 million to $74.9 million in 2014 from $143.2 million in 2013. This expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. The decreasing trend in natural gas prices resulted in a significant impairment in 2014, primarily due to extremely low prices for natural gas.  The impairments in 2014 were primarily due to write-downs of both prospect costs and developed fields.  Prospects impaired included three projects in West Virginia  and South Louisiana, for which impairment totaled approximately $0.7 million. Several developed fields were impaired due to downward revisions in reserves based on both performance and on development drilling results that were below expectations.  The most significant of these were in South Louisiana $31.6 million, East Texas $28.6 million and South Texas $9.6 million. 

Accretion expense is related to our obligation for retirement of oil and natural 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. Accretion expense was $2.2 million and $2.1 million in 2014 and 2013, respectively.

General and administrative expense increased $22.2 million to $69.2 million in 2014 from $47.0 million in 2013. The increase is primarily due to non-recurring capital restructuring expenditures of $13.9 million, increases in salary and benefits totaling $7.1 million primarily due to increased headcount, performance bonus and deferred compensation expense, and settlement expense of $3.4 million.  These increases were partially offset by a decrease in other corporate expenditures of $2.3 million. On a per unit basis, general and administrative expenses increased 33% from $7.74 to $10.30 per BOE for 2013 and 2014, respectively.

Interest expense, net increased $0.7 million to $55.8 million in 2014 from $55.1 million in 2013. This increase is primarily due to higher interest of $0.7 million on our credit facility during 2014 as compared to 2013 due to higher outstanding balances

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, our exploration and development activities, and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2015 capital budget was primarily focused on the development of existing core areas through exploitation and development. For 2016, we have prepared a  capital budget of approximately $115 million for exploration and development, of which approximately 91% is allocated to our properties in Sooner Trend and Weeks Island Area.  We reduced our anticipated capital expenditures for 2016 in response to the significant decline in oil prices sincethe third quarter of 2014and in order to preserve our liquidity.  Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.

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We expect to fund our 2016 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility.  If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. 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.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures.  We cannot assure you that our business will generate sufficient cash flow from operations to service out outstanding indebtedness or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs.  If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as, refinancing or restructuring our debt; selling assets; reducing or delaying acquisitions or our drilling programs, or seeking to raise additional capital.

However, we cannot assure you we would be able to refinance or restructure our debt or implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would allow us to meet our debt obligations.  In additions, any failure to make schedule payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

Senior Notes

We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.  The senior notes are unsecured and are our general obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility and senior secured term loan facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.

The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent, which matures October 13, 2017. As of December 31, 2015, the credit facility was subject to a $300 million borrowing base limit, and we had $152 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.

The borrowing base is redetermined each May and November.  On June 2, 2015 the borrowing base was redetermined and was reduced to $300 million from $375 million.  On September 30, 2015, as a result of our Eagle Ford divestiture, our borrowing base was reduced from $300 million to $255 million.  On November 12, 2015, our borrowing base was redetermined and was increased to $300 million.  On March 16, 2016, we borrowed $141.9 million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility.  As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the Administrative Agent.   Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account. Following the funding of this borrowing, as of March 29, 2016, the outstanding borrowing under the credit facility was $300 million, including $6.1 million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.  If oil and natural gas prices continue to decline, the borrowing base under our credit facility may be reduced.

Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The average rate on all loans outstanding as of December 31, 2015 under the credit facility was 2.87%, which was based on the Eurodollar option.

The credit facility,the indenture governing the senior notes and the senior secured term loan facility include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At December 31, 2015, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Subsequent to year end, on February 3, 2016, we entered into an Agreement and Amendment No. 13 to the credit facility (the “Thirteenth Amendment”). The Thirteenth Amendment, among other things: (a) permits us to enter into exchanges of outstanding senior notes for third lien term loan, (b) permits us to draw the remaining borrowing base availability under the credit facility into a controlled account with such funds not being treated as debt for the purposes of leverage ratio compliance so long as they remain in

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the controlled account, (c) permits us to dispose of oil and natural gas properties pursuant to the Joint Development Agreement with BCE, (d) requires that twice a month we transfer available cash in excess of $25 million to the controlled account, and (e) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.00 to 1.00 to 4.50 to 1.00.

Senior Secured Term Loan

On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “Term Loan Facility”) with Morgan Stanley Energy Capital Inc. as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million.  The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The Term Loan Facility matures on April 15, 2018. 

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  PV-9 is calculated using four year NYMEX strip pricing adjusted for differentials.  Obligations under the Term Loan Facility are guaranteed by certain of our subsidiaries and affiliates and are secured by second priority liens on substantially all of our and our subsidiaries assets that serve as collateral under the credit facility.  At December 31, 2015, we were in compliance with the covenants of the Term Loan Facility.

We have the option to prepay all or a portion of the Term Loan Facility at any time, and we are subject to certain mandatory prepayments of proceeds from asset sales or an initial public offering, which are subject to certain prepayment premiums.  The net proceeds of $121 million from the Term Loan Facility were used to pay down outstanding amounts under our credit facility.

Subsequent to year end, on February 3, 2016, we entered into the first amendment to the Term Loan Facility (the “First Amendment”). The First Amendment: (a) permits us to enter into exchanges of outstanding senior notes for third lien term loan, (b) allows us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE, (c) requires that twice a month we transfer available cash in excess of $25 million to a controlled account, with such funds in the controlled account to not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, and (d) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.50 to 1.00 to 5.00 to 1.00.

Cash Flows Provided by Operating Activities

Operating activities provided cash of $144.0 million in 2015, as compared to $184.9 million in 2014. The $40.9 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $43.2 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $4.5 million as compared to having provided $2.2 million in cash in 2014.

Operating activities provided cash of $184.9 million in 2014, as compared to $172.5 million for 2013. The $12.4 million increase in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net increase of approximately $11.4 million in earnings and a positive impact on cash flow.

Cash Flows Used in Investing Activities

Investing activities used cash of $105.8 million for the year ended December 31, 2015 as compared to $189.7 million for the year ended December 31, 2014. The decrease in cash used in investing activities was primarily related to decreased expenditures for drilling and development, partially offset by lower proceeds from the sale of assets and an increase in acquisitions.  In 2015, the sale of the remaining portion of our interest in the Eagleville field provided net proceeds of approximately $115.0 million and the acquisition of undeveloped leasehold interests in Oklahoma resulted in a use of cash of $47.4 million.  In addition, release of non-invested funds in the restricted cash account, provided cash of $24.6 million.

Investing activities used cash of $189.7 million for the year ended December 31, 2014 as compared to $336.1 million for the year ended December 31, 2013. The decrease in cash used in investing activities was primarily related to proceeds from sale of assets partially offset by increased expenditures for drilling and development.  In 2014, the sale of a portion of our interest in our Eagleville field provided net proceeds of approximately $168.0 million; the sale of our remaining interests in the Hilltop field provided net proceeds of approximately $41.6 million; and the sale of our interest in the Anne Parsons field in East Texas provided proceeds of approximately $8.6 million.  In the third quarter of 2014, we placed the net proceeds from our sale of Hilltop field into a restricted cash account with a qualified intermediary available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code.  As of December 31, 2014, the investment of funds in this restricted cash account, net of expenditures for qualifying property during the period, resulted in a use of cash of $24.6 million. 

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Cash Flows Provided by Financing Activities

Financing activities used cash of $30.6 million during 2015 as compared to $0.4 million during 2014, an increase of $30.2 million.  During 2015, we used proceeds from the sale of our remaining interests in Eagleville properties of $115.0 million and proceeds from the issuance of the Term Loan Facility of $121.0 million, net of issuance cost to reduce the outstanding balance under our credit facility by $295.0 million.  We received $252.5 million in proceeds from long-term debt consisting of $125.0 million under our Term Loan Facility and $127.5 million in borrowings under our credit facility.  We made capital distributions of $3.8 million in 2015 as compared to a capital distribution of $0.5 million in 2014.  We received capital contributions of $20 million from our Class B Partners in 2015.  No contributions were received in 2014.  We incurred $4.3 million of deferred financing cost in 2015 related to the borrowing of the Term Loan Facility. 

Financing activities used cash of $0.4 million during 2014 as compared to cash provided by financing of  $164.4 million during 2013, a decrease of $164.8 million.  During 2014, we used proceeds from the Eagleville divesture to reduce the outstanding balance under our credit facility of $169.3 million, although we also drew down $169.5 million.

Risk Management Activities — Commodity Derivative Instruments

Due to the risk of low oil and natural gas prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls, and financial basis swap contracts) for a portion of our oil,  natural gas, and natural gas liquids production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil, natural gas,  and natural gas liquids prices,  and may partially limit our potential gains from future increases in prices. At December 31, 2015, commodity derivative instruments were in place covering approximately 98% of our projected oil production, approximately 79% of our natural gas production, and approximately 28%of our natural gas liquids production from proved developed properties for 2016. See Note 6 to our consolidated financial statements as of December 31, 2015, “Derivative Financial Instruments”, for further information.

Contractual Obligations

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

	Year Ended December 31,
	Total		2016		2017-2018		2019-2020		Thereafter
	(in thousands)
Debt	$	752,748	$	—	$	727,000	$	—	$	25,748
Interest (1)		169,047		58,200		103,596		—		7,251
Operating Leases		14,603		4,130		4,473		3,173		2,827
Drilling rigs (2)		975		975		—		—		—
Abandonment liabilities (3)		61,218		729		5,382		2,286		52,821
Total	$	998,591	$	64,034	$	840,451	$	5,459	$	88,647

(1) Interest includes interest on the outstanding balance under our revolving credit facility maturing in 2017, payable quarterly; on our Term Loan Facility due 2018, payable quarterly; on our senior notes due 2018, payable semiannually; and on the debt to our founder, which is payable with principal, at maturity in 2021. In June 2015 the debt under our revolving credit facility was amended to extend the maturity from May 2016 to October 2017. Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

(2) The drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed.  The drillings rigs are utilized in drilling wells that may or may not be included as part of our Joint Development Agreement with BCE.   

(3) Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations.

In addition to the items above, we have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid if certain product price conditions are met. We have a commitment in which we must make  a contingent payment of up to $2.0million if we decide to forego certain drilling activities.

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Off-Balance Sheet Arrangements

As of December 31, 2015 we had no guarantees of third party obligations. Our off-balance sheet obligations include the obligations under operating leases, the $2.2 million contingent properties payment, and the $2.0 million drilling commitment noted in “Contractual Obligations” above.  We also have bonds posted in the aggregate amount of $24.4 million, primarily to cover future abandonment costs, and $65,000 in letters of credit provided under our credit facility.  We typically enter into short-term drilling contracts which are customary in the oil and gas industry.  We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

We have no plans to enter into any additional off-balance sheet arrangements in the foreseeable future.

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 (“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 accounting principles generally accepted in the United States. 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 reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Property and Equipment. Oil and natural 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 leases are recorded as unproved properties 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. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, 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. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful

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exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed at least quarterly for impairment following the guidance provided in ASC 360-10-35, Property, Plant and Equipment, Subsequent Measurement, 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 at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Unproved properties 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 consolidated statement of operations.

Depreciation, Depletion and Amortization — Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. 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 lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from the drilling rig has been recorded when services were performed. 

Derivative Financial Instruments.  We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.

Income Taxes. We have elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal operations taxes is included in the consolidated financial statements.

We are subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for state income tax” on the consolidated statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

Asset Retirement Obligations. We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities, and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability 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. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

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Investment . Our investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, our share of earnings or losses of the investment are not included in the consolidated statements of operations. Distributions from Orion are recognized in current period earnings as declared.

Deferred Financing Costs.  The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

In April 2015, the FASB issued ASU2015-03, Simplifying the Presentation of Debt Issuance Costs,  which simplifies the presentation of debt issuance costs. The new standard requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability, whereas they were previously being presented as a component of “deferred charges and other” on the balance sheet. The new standard creates consistency in the way debt issuance costs and debt discounts are presented on the balance sheet and better aligns U.S. GAAP with International Financial Reporting Standards. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. The Company adopted this standard in the fourth quarter 2015. As a result, deferred financing costs of $7.8 million and $6.5 million related to the Company’s senior secured term loan facility and senior unsecured notes were reclassified from deferred financing costs, net to a direct reduction from the debt’s carrying value as of December 31, 2015 and 2014, respectively.  Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

In September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued Accounting Standard Update 2016-02, Leases (Topic 842),  which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

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

Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for natural gas. We have used, and expect to continue to use, oil and natural gas derivative contracts to reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with pre-existing or anticipated sales of oil and natural gas.

As of December 31, 2015, we have hedged approximately 72% of our forecasted production from proved developed reserves through 2019at average annual floor prices ranging from $2.92 per MMBtu to $4.50 per MMBtu for natural gas and $62.50 per Bbl to $72.27 per Bbl for oil. Forecasted production from proved reserves is estimated in our December 2015 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Please read the disclosures under “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” in “Item 1A. Risk Factors” above.

The fair value of our oil and natural gas derivative contracts and basis swaps at December 31, 2015 was a net asset of $104.3 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $20.8 million (decrease in value) or $21.8 million (increase in value), respectively, as of December 31, 2015.

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts. A 1% increase in interest rates (100 LIBOR basis points) would increase interest expense on our variable rate debt by approximately $1.5 million, based on the balance outstanding at December 31, 2015.  

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements and supplementary financial information required to be filed under this item are presented beginning on page F-1 in Part IV, Item 15 of this annual report and are incorporated herein by reference.

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

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2015 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

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Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2015. Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collision or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate.

Our management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to perform its assessment. Based on this assessment, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded, that as of December 31, 2015, our internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance

As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors of our general partner, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”), and the officers and directors of Alta Mesa Services, LP (“Alta Mesa Services”), an entity wholly owned by us. References to our directors are references to the directors of Alta Mesa GP. References to our officers and employees are references to the officers and employees of Alta Mesa Services.

All of our executive management personnel are employees of Alta Mesa Services and devote all of their time to our business and affairs. We also utilize a significant number of employees of Alta Mesa Services to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement, we reimburse Alta Mesa Services for its operational personnel who perform services for our benefit. See “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Shared Services and Expenses Agreement.”

Board Leadership Structure

Our Chairman is Michael E. Ellis, our Chief Operating Officer and founder of the Company. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

Board Oversight of Risk

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this report. The Board of Directors has delegated to management the primary responsibility of risk management, while it has retained oversight of management in that regard.

In addition, our Board of Directors considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our oil and natural gas reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our Board reviews and attempts to mitigate risks which may result from our compensation policies.

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Executive Officers and Directors

The following table sets forth the names, ages and offices of our present directors and executive officers as of December 31, 2015. Members of our Board of Directors are elected for one-year terms.

7
Name	Age	Director Since	Position
Harlan H. Chappelle	59	2005	President, Chief Executive Officer and Director
Don Dimitrievich	45	2014	Director
Michael E. Ellis	59	1987	Founder, Chairman, Vice President of Engineering and Chief Operating Officer
Mickey Ellis	57	1987	Director
Michael A. McCabe	60	2014	Vice President, Chief Financial Officer and Director
David Murrell	54	—	Vice President of Land and Business Development
Homer “Gene” Cole	52	2015	Vice President, Chief Technical Officer and Director

The following is a biographical summary of the business experience of these directors and executive officers:

Harlan H. Chappelle joined Alta Mesa as President, CEO and director in November 2004, and has led us in a period of significant growth, building a strong management and technical team, focusing us on our greatest opportunities, making strategic acquisitions, and restructuring our financing. Mr. Chappelle has over 30 years in field operations, engineering, management, marketing and trading, acquisitions and divestitures, and field re-development. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company, and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin.

Don Dimitrievich was appointed to our Board of Directors as Highbridge’s director nominee in March 2014. Mr. Dimitrievich is a Managing Director at Highbridge Principal Strategies, an alternative investment management organization that together with its affiliates manages approximately $29 billion in capital for institutional investors, pension funds, endowments and foundations.  At Highbridge, Mr. Dimitrievich oversees Highbridge Principal Strategies’ direct credit investment strategy for the energy and power sectors. Highbridge has invested over $1.5 billion in direct energy-related investments. Prior to joining Highbridge in 2012, Mr. Dimitrievich was a Managing Director of Citi Credit Opportunities, a credit-focused principal investment group. At Citi Credit Opportunities, Mr. Dimitrievich oversaw the energy and power portfolio and invested over $800 million in mezzanine, special situation and equity co-investments, and secondary market opportunities. Mr. Dimitrievich began his career as a corporate attorney in the New York office of Skadden, Arps, Slate, Meagher & Flom LLP from 1998 to 2004 focusing on energy mergers and acquisitions and capital markets transactions.  Mr. Dimitrievich also serves on the board of Energy & Exploration Partners, Inc. Mr. Dimitrievich has a Law degree with Great Distinction from McGill University in Montreal, Canada and earned a Chemical Engineering degree with Great Distinction from Queen’s University in Kingston, Canada.

Michael E. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco, and is our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis manages all day-to-day engineering and field operations of Alta Mesa. He built our asset base by starting with small earn-in exploitation projects, then progressively growing the company with successive acquisitions of fields from major oil companies, and consistent success in exploration and development drilling. He has over 30 years’ experience in management, engineering, exploration, and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University.  Mr. Ellis is the spouse of Mickey Ellis, our director.

Mickey Ellis has served as a director since our inception in 1987. Ms. Ellis is actively involved in the leadership of charitable organizations, as a Board Member of Houston Area Respite Care and The Confessing Movement of the United Methodist Church, Treasurer of the National Charity League Star Chapter, Committee Member on several committees within Mission Bend United Methodist Church, and Building Relocation Coordinator for Mission Bend Christian Academy. She is a major fundraiser for the Susan G. Komen Foundation, and an active volunteer for CanCare. Ms. Ellis is the spouse of Michael E. Ellis, our Chairman, Chief Operating Officer and Vice President of Engineering.

Michael A. McCabe, our CFO as well as a Vice President, joined Alta Mesa in September 2006 and became a director in 2014. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. From 2004 until 2006, Mr. McCabe served as President and sole owner of Bridge Management Group, Inc., a private consulting firm primarily providing advisory services to us and to MultiFuels, Inc., a Houston based developer of natural gas storage facilities. He has served in senior positions with Bank of Tokyo, Bank of New England, and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Masters of Science in Chemical Engineering from Purdue University and a Master of Business Administration in Financial Management from Pace University.

David Murrell has served as our Vice President, Land and Business Development since 2006. Mr. Murrell has over 25 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of lease analysts, landmen, and field representatives that has facilitated our company’s growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma.

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Homer “Gene” Cole hasservedin the position of Vice President and Chief Technical Officer since 2015 and became a director in 2015.  Mr. Cole has over 25 years of extensive domestic and international oilfield experience in management, well completions, well stimulation design and execution. He started his career with Schlumberger Dowell as a Field Engineer and servedfrom 1986 to 2007in numerous increasingly responsible positions with Schlumberger in the areas of field operations, engineering and management. He has a Bachelor of Science in Petroleum Engineering from Marietta College.

Qualifications of Directors

Mr. Chappelle’s experience as our Chief Executive Officer since 2004, combined with his significant equity ownership of us, and over 30 years of experience in the oil and gas industry uniquely qualify him to serve as a director of our general partner.

Mr. Ellis is our founder; his experience in that capacity and as one of our executive officers since 1987 provide him intimate knowledge of our operations, finances and strategy and uniquely qualifies him to serve as the Chairman of our general partner.

Ms. Ellis’ role in working with us since our inception in 1987 provides her with valuable knowledge of our business and operations and uniquely qualifies her to serve as a director of our general partner.

Mr. Dimitrievich provides the Board with significant financial and energy expertise which uniquely qualifies him to serve as a director of our general partner.

Mr. McCabe’s experience as our Chief Financial Officer since 2006 and over 25 years of corporate finance experience uniquely qualifies him to serve on our Board.

Mr. Cole’s experience as our Chief Technical Officer since 2015and over 25 years of domestic and international oilfield experience in well completions, and well simulations design and execution uniquely qualifies him to serve on our Board.

Audit and Compensation Committee

We do not have a formal compensation committee and our full Board serves as our audit committee. Because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Directors has not made any determination as to whether any of the members of our Board of Directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, we have not yet determined whether any of our directors is an audit committee financial expert.

Code of Ethics

The Board of Directors has adopted a Code of Ethics for Senior Financial Officers. The Code of Ethics is posted on the investor relations section of our website at www.altamesa.net and is available free of charge upon written request to 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

Item 11. Executive Compensation

Compensation Discussion and Analysis

This Compensation Discussion and Analysis, describes our compensation objectives and the principles underlying our compensation policy relating to 2015 compensation for our named executive officers.

Our Board of Directors is responsible for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.

Objectives of Our Compensation Program

Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results for us. In addition, our program is designed to achieve the following objectives:

•attract and retain highly qualified executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;

•provide total compensation that is justified by individual performance; and

•reward our executives for their contributions to our overall performance as well as for theirindividual performance.

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What Our Compensation Program is Designed to Reward

Our strategy is to increase reserves and production by applying advanced engineering analytics and enhanced geological techniques in areas we have identified as underdeveloped and overlooked. Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy, such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.

Elements of Our Compensation Program and Why We Pay Each Element

To accomplish our objectives, our compensation program is comprised of the following elements: base salary, cash bonus, long term incentives and benefits. Our Board of Directors approved and adopted a deferred compensation and supplemental executive retirement plan in 2013 and a performance appreciation rights plan in 2014.

We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.

We provide a deferred compensation and supplemental retirement plan to certain key employees, including all our executive officers, to provide additional flexibility and tax planning advantages to them.  In addition, the retirement benefitsenhance employee compensation on a discretionary basis and encourage their continued service to us.

We grant performance appreciation rights units as long term compensation to certain key employees, including our executive officers, who make significant contributions to us.  The units are payable on a fixed determination date between five and ten years from the date of the award, and therefore, provide the grantee with a significant interest in us tied to long-term performance.

We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees.  In 2013 we introduced a deferred compensation plan offered to all employees, to provide flexibility and tax planning advantages to them.

How We Determine Each Element of Compensation

In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2015 compensation.

Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services. The employment agreements automatically renew annually, subject to prior notice of cancellation by either Alta Mesa Services or the executive. These employment agreements establish set minimum base salaries for each officer.  On March 25, 2014, these employment agreements were amended and restated and the salaries for each officer were set at $485,000, $485,000, $435,000, and $360,000 per annum, to Messrs. Ellis, Chappelle, McCabe and Murrell, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary if performance criteria set by the Board for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses and participation in employee benefit plans.

Base salary. In reviewing base salaries, the Board takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors the Board considers include individual achievements, our performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the Board’s review and determination of their respective base salaries. For 2015, the Board set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively. In addition, the Board determined Mr. Murrell’s and Mr. Cole’s salary of $360,000 and $300,000 for 2015 was appropriate.

Bonus.  A portion of each executive’s total compensation may be paid as bonus compensation. The Board takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, the Board takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our

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executive officers for 2015 has not yet been determined.However, bonuses paid in 2015 for 2014 performance was awarded to only Mr. Murrell and was approximately 7% of his base salary.

On September 23, 2014, the Board of Directors approved and adopted a long term compensation plan, the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “PARs Plan”) effective September 24, 2014, to provide long term incentive compensation to key employees and consultants who make significant contributions to us to align our employees with our long term performance. The PARs Plan is administered by the Board, which will determine from time to time which participants will participate in the PARs Plan, the number of PARs to be granted to each participant, the initial stipulated designated value of each PAR, the designated value of each PAR as of its valuation date, the vesting schedule of each PAR, and any other terms and conditions of the PAR award. Under the PARs Plan, there are special provisions for accelerated vesting and valuation of a PAR award in the event of a Liquidity Event as follows: (i) a sale of the all of the assets of High Mesa, (ii) a disposition of all of the equity securities of High Mesa, (iii) an initial public offering of the equity securities of High Mesa or any of its subsidiaries that hold all or substantially all of the assets or (iv) a public offering resulting in gross proceeds of at least $300,000,000.  

A total of one million (1,000,000) PARs are available for grants to participants under the PARs Plan. The aggregate designated value of all 1,000,000 PARs is equal to ten percent (10%) of the fair market value of the aggregate interests of all the Class A limited partners in our General Partner.  

Absent an intervening Liquidity Event, payment of a PAR award is made on the fixed determination date elected in advance by the recipient of the PAR award, with such fixed determination date occurring no earlier than five years and no later than ten years from the grant date. All payments made under the PARs Plan in any year are subject to a floating annual cap on the amount of all PAR awards paid under the PARs Plan in a given year (the “Annual Cap”). The Annual Cap is equal to 2.5% multiplied by the fair market value of the aggregate interests of all the Class A limited partners in our General Partner minus $400,000,000 (i.e., [2.50% x (FMV - $400,000,000)]. If the Annual Cap applies in a year, the amount payable to a PAR award holder on the fixed determination date is his pro-rata amount of the aggregate payments to be made on that date as adjusted for the amount of Annual Cap remaining for that year. Any amounts in excess of the Annual Cap are paid in the next following year, again subject to the Annual Cap.

Upon the occurrence of a payment event, the participant will be entitled to receive a cash amount equal to the increase, if any, between the initial stipulated designated value of the PAR as of its grant date and the designated value of the PAR as of its payment valuation date. No PARs will be settled in shares; rather, all PAR exercises will be settled solely in cash. Participants will have no rights whatsoever as a shareholder of Alta Mesa GP or of a subsidiary in respect of any PARs.

In 2015, no PARs were awarded to any of the named executives.  In 2014, the Board awarded 60,000 PARs to Michael A McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three year period.  The stipulated initial designated value (“SIDV”) is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least five years from the date of issuance of the award.  The Board also granted 15,000 PARs to David Murrell, which vest over a five year period.  The SIDV of 10,000 of the units is $40 per unit, and the remaining 5,000 units have a SIDV of $30 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least five years from the date of issuance of the award.

Benefits.  We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis, Chappelle, McCabe, Murrell, and Cole with company automobiles. Beginning annually in 2014, we also reimburse each officer, with the exception of Mr. Cole, up to $5,000 annually for tax preparation and planning.

Nonqualified Deferred Compensation. We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our executives and other key highly compensated employees.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring a very short time or until retirement.  On December 30 2015, the Board, in its discretion, authorized an elective employer contributions to be credited to the accounts of Messrs. Chappelle, Ellis, McCabe,  Murrell, and Cole in the amounts of $1.4 million, $0.9 million, $0.8 million,  $0.3 million and $0.5 million,respectively, effective January 1, 2016.  The Board of Directors elected to make this distribution subject to a five-year vesting schedule, with 20% vested each subsequent year, with the exception of Messrs. Murrell and Cole, with 25% vested each subsequent year beginning in year two of the five-year vesting schedule.

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Other Compensation. As part of his employment agreement, we provide Mr. McCabe an apartment near our headquarters and pay his commuting expenses to and from his permanent home to Houston. In 2015, these housing and commuting expenses totaled approximately $118,000. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence is outside of the Houston area. The Board considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.

How Elements of Our Compensation Program are Related to Each Other

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.

Assessment of Risk

Our Board takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.

Accounting and Tax Considerations

We have structured our compensation program to comply with Internal Revenue Code Section 409A. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such compensation does not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit includible in income.

Under the PARs Plan, participants are granted PARs with a stipulated initial value.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire.  We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan.  We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2015 and 2014.

Compensation Committee Report

As we do not have a formal compensation committee, our entire Board of Directors serves as our compensation committee. Our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review the related discussions and such other matters deemed relevant and appropriate to the Board of Directors, and the Board of Directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

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Summary Compensation

The following table summarizes, with respect to our named executive officers, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2015, 2014 and 2013. None of the named executive officers participate in a defined benefit pension plan.

						All Other
Name and Principal Position:	Year	Salary		Bonus (1) (7)		Compensation			Total
Harlan H. Chappelle	2015	$	485,000	$	—	$	42,555	(2)	$	527,555
President, Chief Executive Officer	2014	$	485,000	$	—	$	38,515	(2)	$	523,515
	2013	$	468,000	$	1,100,000	$	24,051	(2)	$	1,592,051
Michael E. Ellis	2015	$	485,000	$	—	$	20,423	(3)	$	505,423
Chief Operating Officer, Vice President of	2014	$	485,000	$	—	$	13,078	(3)	$	498,078
Engineering and Chairman of the Board	2013	$	468,000	$	700,000	$	12,955	(3)	$	1,180,955
Michael A McCabe	2015	$	435,000	$	—	$	126,095	(4)	$	561,095
Vice President, Chief Financial Officer	2014	$	435,000	$	400,000	$	3,120,848	(4)	$	3,955,848
	2013	$	420,000	$	600,000	$	144,454	(4)	$	1,164,454
David Murrell	2015	$	360,000	$	—	$	14,819	(5)	$	374,819
Vice President of Land and Business Development	2014	$	360,000	$	25,000	$	22,850	(5)	$	407,850
	2013	$	345,000	$	300,000	$	353,937	(5)	$	998,937
Homer "Gene" Cole	2015	$	300,000	$	—	$	21,279	(6)	$	321,279
Vice President, Chief Technical Officer

(1) Bonuses for 2015 have not yet been determined.  We expect these bonuses will be determined before the end of August 2016.

(2) Mr. Chappelle’s other compensation for the year ended December 31, 2015 consists of $8,954 in his matching funds to his 401(k), $30,131 in auto expenses, and approximately $3,470 for club membership.  Mr. Chappelle’s other compensation for the year ended December 31, 2014 consists of $9,110 in matching funds to his 401(k) account and $29,405 in auto expenses.  Mr. Chappelle’s other compensation for the year ended December 31, 2013 consists of $10,200 in matching funds to his 401(k) account and $13,851 in auto expenses. 

(3) Mr. Ellis’ other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $9,823 in auto expenses.  Mr. Ellis’ other compensation for the year ended December 31, 2014 consists of $8,750 in matching funds to his 401(k) account and $4,328 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2013 consists of $8,700 in matching funds to his 401(k) account and $4,255 in auto expenses.

(4) For the year ended December 31, 2015, Mr. McCabe’s other compensation consists of $8,319 in matching funds to his 401(k) account, and $117,776in travel and living expenses, which includes $41,049for an apartment in Houston and $76,727for travel, which consists primarily of airfare and the cost of rental cars and parking. For the year ended December 31, 2014, Mr. McCabe’s other compensation consists of $3,000,000 in an elective contribution made by us to his nonqualified deferred compensation account, $7,131in matching funds to his 401(k) account, and $113,717 in travel and living expenses, which includes $32,597 for an apartment in Houston and $81,120 for travel, which consists primarily of airfare and the cost of rental cars and parking. For the year ended December 31, 2013, Mr. McCabe’s other compensation consisted of $10,200 in matching funds to his 401(k) account, and $134,254 in travel and living expenses, which includes $31,865 for an apartment in Houston and $102,389 for travel, which consists primarily of airfare and the cost of a leased car and parking.

(5) Mr. Murrell’s other compensation for the year ended December 31, 2015 consists of$10,600 in matching funds to his 401(k) account and $4,219 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2014 consists of $11,500 in matching funds to his 401(k) account and $11,350 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2013 consists of $325,000 in an elective contribution made by us to his nonqualified deferred compensation account, $10,200 in matching funds to his 401(k) account and $18,737 in auto expenses.

(6) Mr. Cole became an executive officer of the Company in 2015.  Mr. Cole’s other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $10,679 in auto expense.

(7) In 2014, the Board awarded 60,000 PARs to Michael A McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three year period.  The SIDV is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least 5 years from the date of issuance of the award.  The Board also granted 15,000 PARs to David Murrell, which vest over a 60

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five year period.  The SIDV of 10,000 of the units is $40 per unit, and the remaining 5,000 units have a SIDV of $30 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least five years from the date of issuance of the award.

Narrative Disclosure to Summary Compensation Table

Employment agreements

Mr. Chappelle

Mr. Chappelle entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as President and Chief Executive Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.

Mr. Chappelle’s employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. Ellis

Mr. Ellis entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Operating Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.

Mr. Ellis’ employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe

Mr. McCabe entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Financial Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.

Mr. McCabe’s employment agreement provides for a minimum base salary of $435,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston.

Mr. Murrell

Mr. Murrell entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President of Land and Business Development until March 25, 2015, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.

Mr. Murrell’s employment agreement provides for a minimum base salary of $360,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion, subject to a minimum of $50,000.

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Grants of Plan-Based Awards for Fiscal Year 2015

There were no grants of plan-based awards to our named executive officers during the fiscal year ended December 31, 2015.

Outstanding Equity Awards Value at 2015 Fiscal Year-End

There were no outstanding equity awards for our named executive officers as of December 31, 2015.

Option Exercises and Equity Awards Vested in Fiscal Year 2015

There were no exercises of equity awards and no vesting of equity awards for our named executive officers during fiscal 2015.

Pension Benefits

We do not provide pension benefits for our named executive officers.

Nonqualified Deferred Compensation

We established a nonqualified deferred compensation plan in 2013, theRetirement Plan, to provide additional flexibility and tax planning advantages to our executives and other key highly compensated employees.  The Board of Directors administers the Retirement Plan, and at its sole discretion, designates employees eligible to participate.  Participants may defer up to 90% of their salary and up to 100% of their cash bonus under the program.   The Board of Directors may also, at its sole discretion, make elective employer contributions on behalf of selected participants.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring a very short time or as long as until retirement from us.  The Retirement Plan is an unsecured and unfunded promise to pay the participants, who are our general creditors. 

In 2015, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any named executive.  In 2014, one elective employer contribution was made for the account of Michael A. McCabe.  The Board of Directors elected to make this distribution subject to a three-year vesting schedule, with 50% vested immediately and 16.67% to vest each subsequent year.  In 2013, one elective employer contribution was made for the account of David Murrell.  The Board of Directors elected to make this distribution subject to a four-year vesting schedule, with 20% vested immediately and 20% to vest each subsequent year.

NONQUALIFIED DEFERRED COMPENSATION
		Aggregate							Aggregate		Aggregate
		Balance at	Executive		Company		Aggregate		Withdrawals /		Balance at
		December 31,	Contributions		Contributions		Earnings		Distributions		December 31,
Name		2014 ($)	in 2015 ($)		in 2015 ($) (1)		in 2015 ($)		during 2015 ($)		2015 ($)
Michael A. McCabe	$	3,000,000	$	—	$	—	$	—	$	—	$	3,000,000
David Murrell		325,000		—	$	—	$	—	$	—	$	325,000
(1)  Included in "All Other Compensation" on the Summary Compensation Table.

Termination of Employment and Change–in–Control Provisions

Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements that provide them with post–termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntary not–for–cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2015. In presenting this disclosure, we describe amounts earned through December 31, 2015 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, our estimates of the amounts which would be paid out to the executives upon their termination.

Provisions Under the Employment Agreements

Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of

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reasonable business expenses that were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.

If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years, of the executive’s base salary in effect as of the termination date. Under the terms of Mr. Murrell’s employment agreement, as of December 31, 2015, upon such involuntary termination, he would also be paid 50% of the annual bonus then in effect.  Mr. Murrell’s amended and restated employment agreement now provides for 18 months’ base salary and two times the annual bonus then in effect.  Assuming termination as of December 31, 2015, for both Messrs. Chappelle and Ellis, the termination benefit would have been $970,000; for Mr. McCabe, $870,000; and for Mr. Murrell, $720,000. In addition, all vested amounts in the executive’s deferred supplemental retirement account would be distributed.  Assuming termination as of December 31, 2015, Mr. McCabe and Mr. Murrell, would have received a distribution of $2,000,000 and $195,000.  Our executives are each entitled under their employment agreements to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage, which is 18 months. The executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2015, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $12.00 to each. Our total cost of providing this benefit would have been $32,306 for Mr. Chappelle, $47,198 for Mr. Ellis, $32,306 for Mr. McCabe, and $32,306 for Mr. Murrell.

“Cause” means:

· the executive’s conviction by a court of competent jurisdiction of a crime involving moral turpitude or a felony, or entering the plea of nolo contendere to such crime by the executive;

· the commission by the executive of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon us or any affiliate;

· the engagement by the executive without approval of us and the Board of Directors in any material activity which directly competes with the business of us or any affiliate or which would directly result in a material injury to the business or reputation of us or any affiliate (including the partners of Alta Mesa); or

· the breach by the executive of any material provision of the employment agreement, and the executive’s continued failure to cure such breach within a reasonable time period set by us but in no event less than twenty calendar days after the executive’s receipt of such notice.

“Good reason” means the occurrence of any of the following, if not cured and correct by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:

· the demotion or reduction in title or rank of the executive, or the assignment to the executive of duties that are materially inconsistent with the executive’s current positions, duties, responsibilities and status with us, or any removal of the executive from, or any failure to re-elect the executive to, any of such positions (other than a change due to the executive’s disability or as an accommodation under the Americans with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with (i) the executive’s termination of employment for cause, disability or death, or (ii) the executive’s prior written consent;

· the reduction of the executive’s annual base salary or bonus opportunity as effective immediately prior to such reduction without the prior written consent of the executive; or

· a relocation of the executive’s principal work location to a location in excess of 50 miles from its then current location.

“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been with us for at least five years.

The employment agreements do not separately provide for benefits upon a change of control.

Termination benefits under our supplemental executive retirement plan define “cause” as above for the employment agreements.  Under the terms of the Plan, termination for any reason other than cause would result in a distribution of the participant’s vested balance in the account.  The terms of the Plan also include a change of control provision, under which all balances in the Plan become immediately vested if the participant is terminated during the first year after the change in control for any reason other than cause.  Normal retirement age is defined under the Plan as 65 years of age.

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Compensation of Directors

The employee and non-employee members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending Board meetings.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee. None of our executive officers has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

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

The following table sets forth as of March 29, 2016 the limited partnership interests in Alta Mesa beneficially owned by:

· all persons who, to the knowledge of our management team, beneficially own more than 5% of our outstanding limited partnership interests;

· each current director of our General Partner;

· each principal officer of our General Partner; and

· all current directors and principal officers of the General Partner as a group.

	Number	Percentage	Number	Percentage
	of Class A	of Class A	of Class B	of Class B
	Units	Units	Units	Units
	Beneficially	Beneficially	Beneficially	Beneficially
Name of Beneficial Owner (1)	Owned	Owned	Owned	Owned
High Mesa Inc. (2)	10,000	10.00%	100,000	100.0%
Michael E. Ellis (3)	85,050	85.05%	—	—
Mickey Ellis (4)	—	—	—	—
Harlan H. Chappelle	4,500	4.50%	—	—
Don Dimitrievich	—	—	—	—
Michael A. McCabe	—	—	—	—
David Murrell	—	—	—	—
Homer "Gene" Cole	—	—	—	—
Directors and principal officers as a group (7 persons)	99,550	99.55%	—	—

(1) Unless otherwise indicated, the address for all beneficial owners in this table is at 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

(2) Our Class A limited partners collectively own all of the common stock of High Mesa Inc. in the same proportions as their interest in us.

(3) Mr. Ellis does not own directly any partnership interests. Includes Class A limited partner interests held by Alta Mesa Resources, LP, Galveston Bay Resources Holdings, LP, Petro Acquisition Holdings, LP and Petro Operating Company Holdings, Inc., all entities owned and controlled by Mr. Ellis.

(4) Mickey Ellis is the spouse of Michael E. Ellis. Ms. Ellis may be deemed to be the beneficial owner of the partnership interests owned by Mr. Ellis.

Additionally, our General Partner, is owned by Mr. and Ms. Ellis and High Mesa, Inc.

Securities Authorized for Issuance under Equity Compensation Plans

We do not have any equity compensation plans.

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

We do not have any formal policy with respect to the review and approval of related party transactions.  A “Related Party Transaction” is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest and the aggregate amount involved is expected to exceed $120,000 in any calendar year. “Related Party” includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest.

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Ownership in Us and Our General Partner 

Michael E. Ellis, our Chairman and Chief Operating Officer, and his spouse Mickey Ellis, one of our directors, own 85.05% of our Class A interests. Our General Partner is owned by Alta Mesa Resources, LP, an entity owned by Michael E. Ellis, Mickey Ellis, and High Mesa. Our General Partner has a 0.1% interest in us.

During 2015 and 2014 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received capital distributions from us of zero and $516,500, respectively.

Founder Notes

We were founded in 1987 by Michael E. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. On March 25, 2014, these notes were amended and restated.  The maturity date of the notes was extended to December 31, 2021.  The interest rate and interest payment terms were not changed.  The founder notes bear simple interest at 10% with a balance of $25.7 million and $24.5 million at December 31, 2015 and December 31, 2014, respectively. Interest and principal are payable at maturity. The notes are convertible into shares of our Class B partner, High Mesa common stock upon certain conditions in the event of an initial public offering.

These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.

Land Consulting Services

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2015, 2014 and 2013, were approximately $133,000, $150,000 and $175,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

Employee and Distribution

David McClure, our Vice President, Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $275,000, $450,000, and $390,000 for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other Vice Presidents whose duties include field oversight.

David Pepper, one of our Landmen, and the cousin of our Vice President, Land and Business Development David Murrell, received total compensation of $146,000, $260,000, and $125,000for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other Landman whose duties include field oversight.

Midstream Asset Sale and Land Purchase

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B partner, High Mesa for $25.5 million cash and short-term note receivable of $8.5 million, while recording no gain or loss on the sale at December 31, 2014.  On January 2, 2015, the $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from Northwest Gas Processing, LLC (“NWGP”) to High Mesa Services, LLC (“HMS”), a subsidiary of High Mesa. 

On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million.  The receivables due from affiliate balance of $1.0 million as of December 31, 2015 includes the cost of repurchasing the land from NWGP.

Director Independence

Our Board of Directors consists of six members, two of whom are non-employee directors. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

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Item 14. Principal Accountant Fees and Services

Our Board of Directors selected BDO USA, LLP (“BDO”), an independent registered public accounting firm, to audit our consolidated financial statements for the fiscal year ended December 31, 2015 and 2014. Our Board of Directors had previously selected UHY LLP (“UHY”), an independent registered public accounting firm, to audit our consolidated financial statements for the fiscal years ended December 31, 2013 and 2012. The Texas practice of UHY was sold to BDO during 2014. As a result, UHY resigned as our independent registered public accounting firm on December 1, 2014, andthe Board of Directors engaged BDO as the Company’s independent registered public accountant for our fiscal year ending December 31, 2014.   Aggregate fees for professional services rendered to us by BDO for the years ended December 31, 2015 and 2014 were as follows:

Audit Fees

	2015		2014
	(in thousands)
Audit fees	$	559,379	$	549,690
Audit-related fees		56,535		38,800
Total	$	615,914	$	588,490

The audit fees for the years ended December 31, 2015 and 2014, respectively, were for professional services rendered for the audits of our consolidated financial statements and review of our quarterly financial statements. 

Audit-related fees

Audit-related fees for the years 2015 and 2014 include fees for the audit of our 401(k) employee savings plan.

Pre-Approval Policies and Procedures

We currently have no Board committees. Our Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by BDO during fiscal 2015 and 2014 were approved by the Board of Directors.  The Board of Directors also considers whether the provision of the foregoing services is compatible with maintaining the auditor’s independence and has concluded that the foregoing non-audit services and non-audit-related services, did not adversely affect the independence of our auditors.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)Documents filed as part of this report:

1.Financial Statements:

(i)Independent Registered Public Accounting Firms’ Reports

(ii)Consolidated Balance Sheets as of December 31, 2015 and 2014

(iii)Consolidated Statements of Operations for each of the three years in the period ended December 31, 2015

(iv)Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2015

(v)Consolidated Statements of Changes in Partners’ (Deficit) for each of the three years in the period ended December 31, 2015

(vi)Notes to Consolidated Financial Statements

(vii)Supplemental Oil and Natural Gas Information (Unaudited)

2.Financial Statement Schedules:

(i)All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

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3.Exhibits:

EXHIBIT NUMBER	Description Of Exhibit
3.1	Articles of Organization of Alta Mesa Holdings GP, LLC dated as of September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
3.2	Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated as of March 25, 2014 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s annual report on Form 10-K filed with the SEC on March 28, 2014).
3.3	Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated as of September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
3.4	Second Amended and Restated Limited Partnership Agreement of Alta Mesa Holdings, LP, dated as of March 25, 2014 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).
3.7	Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
3.8	Bylaws of Alta Mesa Finance Services Corp., dated as of September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
4.1	Indenture by and among the Issuers, the Subsidiary Guarantors and Wells Fargo Bank, N.A., as Trustee, dated as of October 13, 2010 (incorporated by reference from Exhibit 4.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
10.1	Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of May 13, 2010 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
10.2	Amendment No. 1 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, the guarantors parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of September 2, 2010 (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
10.3	Amendment No. 2 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, the guarantors parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of December 6, 2010 (incorporated by reference from Exhibit 10.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).
10.4	Amended and Restated Employment Agreement, dated March 25, 2014, between Alta Mesa Services, LP and Harlan H. Chappelle (incorporated by reference from Exhibit 10.4 to Alta Mesa Holdings, LP’s annual report on Form 10-K filed with the SEC on March 28, 2014).
10.5	Amended and Restated Employment Agreement, dated March 25, 2014, between Alta Mesa Services, LP and Michael E. Ellis (incorporated by reference from Exhibit 10.5 to Alta Mesa Holdings, LP’s annual report on Form 10-K filed with the SEC on March 28, 2014).
10.6	Amended and Restated Employment Agreement, dated March 25, 2014, between Alta Mesa Services, LP and Michael A. McCabe (incorporated by reference from Exhibit 10.6 to Alta Mesa Holdings, LP’s annual report on Form 10-K filed with the SEC on March 28, 2014).
10.7	Amended and Restated Employment Agreement, dated March 25, 2014, between Alta Mesa Services, LP and F. David Murrell (incorporated by reference from Exhibit 10.7 to Alta Mesa Holdings, LP’s annual report on Form 10-K filed with the SEC on March 28, 2014).
10.8	Second Amended and Restated Promissory Note, dated March 25, 2014 executed by Galveston Bay Resources, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.3 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).

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10.9	Second Amended and Restated Promissory Note, dated March 25, 2014 executed by Alta Mesa Holdings, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.4 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).
10.10	Second Amended and Restated Promissory Note, dated March 25, 2014, executed by Petro Acquisitions, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.5 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).
10.11	Amendment No. 3 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of May 23, 2011 (incorporated by reference from Exhibit 10.20 to Alta Mesa Holdings, LP’s registration statement on Form S-4/A filed with the SEC on July 11, 2011).
10.12	Amendment No. 5 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of May 15, 2012 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on May 15, 2012).
10.13	Amendment No. 4 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of November 7, 2011 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on November 14, 2011).
10.14	Alta Mesa Holdings, L. P. Supplemental Executive Retirement Plan, dated August 8, 2013 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 20, 2013).
10.15	Purchase and Sale Agreement dated March 25, 2014 among AM Eagle LLC and Memorial Production Partners LP (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).
10.16	Amendment No. 7 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of March 25, 2014 (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on March 26, 2014).
10.17	Agreement and Amendment No. 8 dated May 12, 2014 to the Sixth Amended and Restated Credit Agreement dated May 13, 2010 among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Wells Fargo Bank, N.A. as administrative agent for such lenders (incorporated by reference from Exhibit 10.10 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on May 13, 2014).
10.18	Master Assignment, Agreement and Amendment No. 9 dated August 5, 2014 to the Sixth Amended and Restated Credit Agreement dated May 13, 2010 among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Wells Fargo Bank, N.A. as administrative agent (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on August 7, 2014).
10.19	Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan dated effective September 24, 2014 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on October 2, 2014).
10.20	Senior Secured Term Loan Agreement dated June 2, 2015 among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Morgan Stanley Energy Capital Inc. as administrative agent for such lenders (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on June 3, 2015).
10.21	Purchase and Sale Agreement dated September 16, 2015 by and among Alta Mesa Holdings, LP, Alta Mesa Eagle, LLC, EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on September 22, 2015).

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10.22	Agreement and Amendment No. 11 dated June 2, 2015 to the Sixth Amended and Restated Credit Agreement among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Wells Fargo Bank, N.A. as administrative agent for such lenders (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on June 3, 2015).
10.23	Agreement and Amendment No. 12 dated September 30, 2015 to the Sixth Amended and Restated Credit Agreement among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Wells Fargo Bank, N.A. as administrative agent for such lenders (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on October 2, 2015).
10.24	Agreement and Amendment No. 13 dated February 3, 2016 to the Sixth Amended and Restated Credit Agreement among Alta Mesa Holdings, LP, certain affiliate Guarantors, the lenders party thereto and Wells Fargo Bank, N.A. as administrative agent for such lenders (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
10.25	First Amendment to Senior Secured Term Loan Agreement dated as of February 3, 2016 to Senior Secured Term Loan Agreement by and among Alta Mesa Holdings, LP, the lenders party thereto from time to time, and Morgan Stanley Energy Capital Inc., as administrative agent for such lenders (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
21.1*	Subsidiaries of the Company.
23.1*	Consent of Ryder Scott Company, L. P.
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
99.1*	Audit Letter by Ryder Scott Company, L. P., dated as of March24, 2016
101*	Interactive Data Files.

*Filed herewith.

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ALTA MESA HOLDINGS, L.P.

(Registrant)

By	/S/ MICHAEL A. MCCABE
	Michael A. McCabe Chief Financial Officer

Dated March 29, 2016

In accordance with the Exchange Act, this report has been signed below on the 29th day of March, 2016, by the following persons on behalf of the registrant and in the capacities indicated.

	Signature	Title
By:	/s/ HARLAN H. CHAPPELLE Harlan H. Chappelle	President, Chief Executive Officer and Director (Principal Executive Officer)
By:	/s/ MICHAEL E. ELLIS Michael E. Ellis	Founder, Chairman, Vice President of Engineering and Chief Operating Officer, Director
By:	/s/ MICKEY ELLIS Mickey Ellis	Director
By:	/s/ MICHAEL A. MCCABE Michael A. McCabe	Vice President, Chief Financial Officer and Director (Principal Financial Officer)
By:	/s/ DON DIMITRIEVICH Don Dimitrievich	Director
By:	/s/ RONALD J. SMITH Ronald J. Smith	Vice President, Chief Accounting Officer (Principal Accounting Officer)
By:	/s/ HOMER “GENE” COLE Homer “Gene” Cole	Vice President, Chief Technical Officer and Director

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“3-D seismic”. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Bbl”. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf”. One billion cubic feet of natural gas.

“Bcfe”. One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

“Basin”. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“BOE”.  One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Btu or British Thermal Unit”. The quantity of 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 natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A”. Depreciation, depletion and amortization.

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

“Developed oil and natural gas reserves”. Developed oil and natural gas reserves are 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 related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

“Dry hole”. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Dry hole costs”. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

“Enhanced recovery”. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well”. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“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. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation”. A layer of rock which has distinct characteristics that differs from nearby rock.

“Fracing, fracture stimulation technology, hydraulic fracturing”. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

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“Gross acres or gross wells”. The total acres or wells, 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.

“Infill wells”. Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“Lease operating expenses”. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl”. One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcf”. One thousand cubic feet of natural gas.

“Mcfe”. One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Mcfe/d”. Mcfe per day.

“MMBtu”. One million British thermal units.

“MMcf”. One million cubic feet of natural gas.

“MMcfe”. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMcfe/d”. MMcfe per day.

“MMBbl”. One million barrels of crude oil, condensate or natural gas liquids.

“NGLs” or “natural gas liquids.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX”. The New York Mercantile Exchange.

“Net Acres”. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Non-operated working interests”. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

“Pay”. A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“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 deemed to have potential for the discovery of commercial hydrocarbons.

“PDNP”. Proved developed non-producing reserves.

“PDP”. Proved developed producing reserves.

“Proved reserves”. Proved oil and natural gas reserves are those quantities of oil and natural 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 — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves (“PUD”)”. Proved undeveloped oil and natural gas reserves are 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. Undrilled acreage is considered proved where adjacent undrilled portions of the reservoir can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available

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geoscience and engineering data.  In addition, reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty and these locations must have a development plan that calls for development within five years, unless specific circumstances justify a longer time.  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  Finally, reserves which can be produced through the application of improved recovery techniques, including injection, may be included upon successful testing of a pilot project in a representative area or analogous reservoir or if other evidence using reliable technology establishes the reasonable certainty of the engineering analysis.  Such improved recovery techniques must be approved for development by all necessary parties and entities including governmental entities.

“PV-10”. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this report.

“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.

“Reserve life index”. A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

“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 separate from other reservoirs.

“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.

“Standardized measure”. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission, without giving effect to non — property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.

“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.

“Unit”. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood”. The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

“Wellbore”. The hole drilled by the bit that is equipped for natural 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 natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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INDEX TO FINANCIAL STATEMENTS

Below is an index to the financial statements and notes contained in Financial Statements and Supplementary Data.

	Page
Audited Financial Statements
Reports of Independent Registered Public Accounting Firms	F-1
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Changes in Partners’ Deficit	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Alta Mesa Holdings, LP and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of Alta Mesa Holdings, LP and Subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in partners’ deficit and cash flows for each of the years in the two year period ended December 31, 2015. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Alta Mesa Holdings, LP and Subsidiaries as of December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the years in the two year period ended, December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/S/ BDO USA, LLP

Houston, Texas

March 29, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Alta Mesa Holdings, LP and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated statements of operations, changes in partners’ deficit, and cash flows of Alta Mesa Holdings, LP and Subsidiaries (the “Company”) for the year ended December 31, 2013.These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the Company’sresults of operations and cash flows for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/S/ UHY LLP

Houston, Texas

March 27, 2014

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,		December 31,
	2015		2014
	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8,869	$	1,349
Restricted cash		105		23,793
Accounts receivable, net of allowance of $1,402 and $1,449, respectively		27,111		43,581
Other receivables		18,526		8,238
Receivables due from affiliate		1,053		25,500
Prepaid expenses and other current assets		4,774		2,132
Derivative financial instruments		62,631		59,803
Total current assets		123,069		164,396
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		525,942		686,176
Other property and equipment, net		11,097		11,505
Total property and equipment, net		537,039		697,681
OTHER ASSETS
Long-term restricted cash		—		900
Investment in LLC — cost		9,000		9,000
Deferred financing costs, net		1,199		1,634
Notes receivable due from affiliate		9,213		8,500
Advances to operators		37		619
Deposits and other assets		1,333		1,124
Derivative financial instruments		41,635		27,271
Total other assets		62,417		49,048
TOTAL ASSETS	$	722,525	$	911,125
LIABILITIES AND PARTNERS’ DEFICIT
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	84,002	$	117,560
Current portion, asset retirement obligations		729		1,136
Total current liabilities		84,731		118,696
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		60,491		61,736
Long-term debt, net		717,775		761,142
Notes payable to founder		25,748		24,540
Other long-term liabilities		10,829		6,457
Total long-term liabilities		814,843		853,875
TOTAL LIABILITIES		899,574		972,571
Commitments and Contingencies (Note 11)
PARTNERS’ DEFICIT		(177,049)		(61,446)
TOTAL LIABILITIES AND PARTNERS’ DEFICIT	$	722,525	$	911,125

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended
	December 31,
	2015		2014		2013
	(in thousands)
OPERATING REVENUES AND OTHER
Oil	$	199,799	$	347,842	$	297,836
Natural gas		30,621		65,002		61,350
Natural gas liquids		10,864		18,281		15,264
Other revenues		682		1,003		1,207
Total operating revenues		241,966		432,128		375,657
Gain (loss) on sale of assets		67,781		87,520		(2,715)
Gain (loss) on derivative contracts		124,141		96,559		(17,150)
Total operating revenues and other		433,888		616,207		355,792
OPERATING EXPENSES
Lease and plant operating expense		71,736		73,820		70,450
Production and ad valorem taxes		15,131		28,214		26,369
Workover expense		6,511		8,961		13,679
Exploration expense		42,718		61,912		33,065
Depreciation, depletion, and amortization expense		143,969		141,804		118,558
Impairment expense		176,774		74,927		143,166
Accretion expense		2,076		2,198		2,133
General and administrative expense		44,454		69,198		47,023
Total operating expenses		503,369		461,034		454,443
INCOME (LOSS) FROM OPERATIONS		(69,481)		155,173		(98,651)
OTHER INCOME (EXPENSE)
Interest expense		(62,473)		(55,812)		(55,188)
Interest income		723		15		124
Total other income (expense)		(61,750)		(55,797)		(55,064)
INCOME (LOSS) BEFORE STATE INCOME TAXES		(131,231)		99,376		(153,715)
(Provision) for state income taxes		(562)		(176)		—
NET INCOME (LOSS)	$	(131,793)	$	99,200	$	(153,715)

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ DEFICIT

YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013

(in thousands)

BALANCE, DECEMBER 31, 2012	$	(6,368)
DISTRIBUTIONS		(24)
NET LOSS		(153,715)
BALANCE, DECEMBER 31, 2013		(160,107)
DISTRIBUTIONS		(539)
NET INCOME		99,200
BALANCE, DECEMBER 31, 2014		(61,446)
CONTRIBUTIONS		20,000
DISTRIBUTIONS		(3,810)
NET LOSS		(131,793)
BALANCE, DECEMBER 31, 2015	$	(177,049)

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(131,793)	$	99,200	$	(153,715)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		143,969		141,804		118,558
Impairment expense		176,774		74,927		143,166
Accretion expense		2,076		2,198		2,133
Amortization of loan costs		3,392		2,885		2,839
Amortization of debt discount		510		510		510
Dry hole expense		22,708		30,294		15,295
Expired leases		6,526		4,319		3,289
(Gain) loss on derivative contracts		(124,141)		(96,559)		17,150
Settlements of derivative contracts		106,949		9,493		18,177
Interest converted into debt		1,208		1,209		1,208
Interest on notes receivable due from affiliate		(713)		—		—
(Gain) loss on sale of assets		(67,781)		(87,520)		2,715
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture		—		(106)		2,305
Accounts receivable		16,470		(95)		(2,771)
Other receivables		(10,288)		(5,686)		1,863
Receivables due from affiliate		(1,725)		—		—
Prepaid expenses and other non-current assets		(2,269)		7,251		4,477
Settlement of asset retirement obligation		(1,794)		(3,942)		(1,548)
Accounts payable, accrued liabilities, and other long-term liabilities		3,900		4,702		(3,132)
NET CASH PROVIDED BY OPERATING ACTIVITIES		143,978		184,884		172,519
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(223,604)		(366,090)		(311,438)
Acquisitions		(48,202)		(18,110)		(51,377)
Proceeds from sale of property		141,404		177,476		26,668
Proceeds from property divesture classified as restricted cash		—		41,590		—
Investment in restricted cash related to property divestitures		24,587		(24,587)		—
NET CASH USED IN INVESTING ACTIVITIES		(105,815)		(189,721)		(336,147)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		252,500		169,500		214,500
Repayments of long-term debt		(295,020)		(169,270)		(50,000)
Additions to deferred financing costs		(4,313)		(42)		(97)
Capital distributions		(3,810)		(539)		(24)
Capital contributions		20,000		—		—
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(30,643)		(351)		164,379
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		7,520		(5,188)		751
CASH AND CASH EQUIVALENTS, beginning of period		1,349		6,537		5,786
CASH AND CASH EQUIVALENTS, end of period	$	8,869	$	1,349	$	6,537
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	56,579	$	51,219	$	50,731
Cash paid (received) during the period for state taxes	$	751	$	(123)	$	18
Change in asset retirement obligations	$	487	$	2,643	$	854
Asset retirement obligations assumed, purchased properties	$	—	$	3,002	$	5,480
Change in accruals or liabilities for capital expenditures	$	(34,160)	$	23,858	$	(14,085)
Non-cash divestiture of oil and gas properties	$	—	$	(34,000)	$	—
Non-cash acquisition of property and land	$	2,473	$	—	$	—

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013

NOTE 1 — NATURE OF OPERATIONS

Nature of Operations.  Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our core properties are located in Oklahoma and Louisiana.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”).  Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ deficit.

Principles of Consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

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 reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. 

Restricted Cash.The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2015, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute.  As of December 31, 2014, the Company had $24.6 million of proceeds remaining in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code from the sale of our Hilltop field Deep Bossier properties. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions, and in March 2015, the remaining $23.7 million of restricted cash was returned to us to be used for general corporate purposes and, as such, was classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014.  The Company planned to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures.

Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized.  Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $9.8 million and $10.3 million at December 31, 2015 and 2014, respectively.  Trade receivables from the sale of oil and natural gas were $17.9 million and $35.1 million at December 31, 2015 and 2014, respectively.  See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM

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Energy Management, LLC (“AEM”).  Accounts receivable from AEM were $12.6 million and $16.6 million as of December 31, 2015 and 2014, respectively.

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.

Deferred Financing Costs.The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

In the fourth quarter of 2015, the Company adopted Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs.  In accordance with the new guidance, deferred financing costs related to the Company’s senior unsecured notes and Term Loan Facility (as defined in Note 9), which had been included in deferred financing costs, net under other assets on the consolidated balance sheets prior to the adoption of ASU 2015-03, are now included in long-term debt on the consolidated balance sheets, resulting in decreases in both deferred financing costs, net and long-term debt of $7.8 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual period presented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the consolidated balance sheet as of December 31, 2014 included a deduction for deferred financing costs of $6.5 million in long-term debt, which had previously been presented in deferred financing costs, net under other assets. Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

Property and Equipment. Oil and natural 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 leases are recorded as unproved properties 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. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet 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. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. 

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas 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.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or 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 at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

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Our evaluation of the Company’s proved properties resulted in impairment expense of $172.0 million, $72.9 million and $135.2 million for the years ended December 31, 2015, 2014, and 2013, respectively, primarily due to lower forecasted commodity prices.

Unproved properties 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 properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2015, 2014 and 2013, impairment expense of unproved properties was $4.8 million, $2.0 million, and $8.0 million, respectively.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2015, 2014, and 2013, respectively, the Company did not record any impairment expense related to other long-lived assets.

Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. 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 lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

DD&A expense for the years ended December 31, 2015, 2014, and 2013 related to oil and natural gas properties was $140.9 million, $139.0 million, and $115.5 million, respectively.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2015, 2014, and 2013 was $3.0 million, $2.8 million, and $3.1 million respectively.

Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.

Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.  Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in

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earnings as “Gain (loss) on derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows. 

Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “ Provision for state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

We have considered our exposure under the standard at both the federal and state tax levels.  We have not recorded any liabilities for uncertain tax positions as of December 31, 2015 and 2014. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2015,  2014, or 2013.  

The Company’s tax returns for the years ended December 31, 2012 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed.

Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk.The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.  We have estimated the fair value of our $450 million senior notes payable at $162 million on December 31, 2015. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 5 – Fair value disclosures and Note 9 - Long-term debt.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”).  ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach. 

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In September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments,  which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

2015 Activity

Alta Mesa Eagle, LLC Divestiture

On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”).  AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas.  In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area.  The effective date of the transaction (the “Effective Date”) is July 1, 2015.

The aggregate cash purchase price for the Membership Interests was $125 million subject to certain adjustments, consisting of $118 million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received.  The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date.  As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million.  Cash received was utilized to pay down borrowings under our credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.

The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118.5 million in pre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below. 

Kingfisher Leasehold Acquisition

On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma.  The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments.  The effective date of the acquisition was April 1, 2015.  The purchase was funded with borrowings under our credit facility.  

2014 Activity

Eagleville Divestiture

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On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The initial cash purchase price was $173 million, subsequently adjusted to approximately $171 million for settlement adjustments.  The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date.  As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE.  We recorded a gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained.

The sold portion of Eagleville field contributed approximately $11.1 million in the first quarter of 2014, prior to its sale. The sold portion of Eagleville field contributed approximately $47.0 million in net pre-tax profit for the year ended December 31, 2013.

Hilltop Divestiture

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a gain on the sale of $15.9 million.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.

The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014.

2013 Activity

Hilltop Divestiture

On October 2, 2013, we closed the sale of certain of our properties in East Texas, comprising a portion of our Hilltop field. The properties sold were primarily producers of dry natural gas located in Leon County, Texas. As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2 BCFE. The cash purchase price was approximately $19 million (net of costs of the sale).  There was no material gain on the sale.  The Hilltop interests contributed approximately $6.9 million in net pre-tax loss during the year ended December 31, 2013.

Weeks Island Acquisition

On October 1, 2013, we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $42 million plus related abandonment costs. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 million BOE as of the effective date of July 1, 2013.  

A summary of the consideration paid and the allocation of the purchase prices are as follows:

	October 1,
	2013
	(in thousands)
Summary of Consideration
Cash	$	41,841
Fair value of asset retirement obligations assumed		5,311
Total	$	47,152
Summary of Purchase Price Allocation
Proved oil and natural gas properties	$	30,279
Unproved oil and natural gas properties		16,873
Total	$	47,152

The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from the date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2013, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods. 

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	Total		Income
	Revenue		(Loss)
	(in thousands)
Actual results of Stone included in our statement of operations for the period October 1, 2013
through December 31, 2013	$	10,509	$	8,575
Pro forma results for the combined entity for the year ended December 31, 2013	$	376,063	$	(146,866)

Other

During 2013, we sold our drilling rig for a cash purchase price of approximately $7.0 million and recorded a loss on sale of approximately $1.2 million.

NOTE 4 — PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	December 31,		December 31,
	2015		2014
	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	127,551	$	84,620
Accumulated impairment		(2,684)		(3,749)
Unproved properties, net		124,867		80,871
Proved oil and natural gas properties		1,345,482		1,417,785
Accumulated depreciation, depletion, amortization and impairment		(944,407)		(812,480)
Proved oil and natural gas properties, net		401,075		605,305
TOTAL OIL AND NATURAL GAS PROPERTIES, net		525,942		686,176
LAND		3,868		2,820
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		18,794		17,302
Accumulated depreciation		(11,565)		(8,617)
OTHER PROPERTY AND EQUIPMENT, net		7,229		8,685
TOTAL PROPERTY AND EQUIPMENT, net	$	537,039	$	697,681

Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well costs during2015,2014, and2013. The table does not include amounts that were capitalized and either subsequently expensed within the same year.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	13,301	$	20,317	$	3,863
Additions to capitalized well costs pending determination of proved reserves		4,364		15,870		21,387
Reclassifications to proved properties		(8,583)		(6,593)		(4,933)
Capitalized exploratory well costs charged to expense		(3,076)		(16,293)		—
Balance, end of year	$	6,006	$	13,301	$	20,317

The ending balance in capitalized exploratory well costs includes the costs of six wells primarily in two prospects that were capitalized for periods greater than one year at December 31, 2015.  We have capitalized $3.0 million and $2.2million of exploratory well costs covering periods greater than one year at December 31, 2015 and 2014.

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NOTE 5 — FAIR VALUE DISCLOSURES

The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (NYMEX) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2.

Our senior notes are carried at historical cost, net of unamortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.

Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $499.6 million were written down to their fair value of $322.8 million, resulting in an impairment charge of $176.8 million for the year ended December 31, 2015. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. Oil and natural gas properties with a carrying amount of $237.2 million were written down to their fair value of $94.0 million, resulting in an impairment charge of $143.2 million for the year ended December 31, 2013. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

In connection with the Stone acquisition in 2013, we recorded oil and natural gas properties with a fair value of $47.2 million.  Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015.  We recorded a total of $4.1 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2014.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

	Level 1		Level 2		Level 3		Total
		(in thousands)
At December 31, 2015:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	166,106		—	$	166,106
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	61,840		—	$	61,840
At December 31, 2014:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	140,652		—	$	140,652
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	53,578		—	$	53,578

The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.

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For additional information on derivative contracts, see Note 6.

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month.  The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes.

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets.  Likewise, derivative (liabilities) could be presented in an asset account.

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

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					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2015	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	86,000	$	(23,369)	$	62,631
Derivative financial instruments, long-term assets		80,106		(38,471)		41,635
Total	$	166,106	$	(61,840)	$	104,266

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2015	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	23,369	$	(23,369)	$	—
Derivative financial instruments, long-term liabilities		38,471		(38,471)		—
Total	$	61,840	$	(61,840)	$	—

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2014	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	91,341	$	(31,538)	$	59,803
Derivative financial instruments, long-term assets		55,325		(28,054)		27,271
Total	$	146,666	$	(59,592)	$	87,074

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2014	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	31,538	$	(31,538)	$	—
Derivative financial instruments, long-term liabilities		28,054		(28,054)		—
Total	$	59,592	$	(59,592)	$	—

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The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

Derivatives not
designated as hedging	Location of	Year Ended December 31,
instruments under ASC 815	Gain (Loss)	2015		2014		2013
		(in thousands)
Oil commodity contracts	Gain (loss) on derivative contracts	$	113,295	$	82,510	$	(17,715)
Natural gas commodity contracts	Gain on derivative contracts		10,712		14,049		565
Natural gas liquids commodity contracts	Gain on derivative contracts		134		—		—
Total gains (losses) from
derivatives not designated as hedges		$	124,141	$	96,559	$	(17,150)

Other receivables includes $17.5 million and $8.0 million of derivative positions settled, but not yet received as of December 31, 2015 and 2014, respectively.  

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

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We had the following open derivative contracts for crude oil at December 31, 2015:

OIL DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2016
Price Swap Contracts	2,532,300	$	64.16	$	94.92	$	53.00
Collar Contracts
Short Call Options	739,100		99.69		130.00		75.00
Long Put Options	603,800		63.71		95.00		40.55
Short Put Options	420,800		72.81		75.00		65.00
2017
Collar Contracts
Short Call Options	1,960,150		85.02		113.83		62.50
Long Put Options	1,412,650		72.27		90.00		60.00
Short Put Options	1,412,650		54.63		70.00		45.00
2018
Collar Contracts
Short Call Options	1,183,000		80.51		104.65		72.00
Long Put Options	1,183,000		67.05		80.00		62.50
Short Put Options	1,183,000		48.90		60.00		45.00
2019
Collar Contracts
Short Call Options	821,250		75.17		75.70		74.50
Long Put Options	821,250		62.50		62.50		62.50
Short Put Options	821,250		45.00		45.00		45.00

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We had the following open derivative contracts for natural gas at December 31, 2015:

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2016
Price Swap Contracts	7,320,000	$	3.05	$	3.17	$	2.95
Collar Contracts
Short Call Options	1,510,000		2.40		2.40		2.40
Long Put Options	1,510,000		2.25		2.25		2.25
2017
Collar Contracts
Short Call Options	6,570,000		5.00		5.00		4.98
Long Put Options	6,570,000		4.50		4.50		4.50
Short Put Options	6,570,000		4.00		4.00		4.00
2018
Collar Contracts
Short Call Options	5,475,000		5.50		5.53		5.48
Long Put Options	5,475,000		4.50		4.50		4.50
Short Put Options	5,475,000		4.00		4.00		4.00

In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks.

We had the following open derivative contracts for natural gas liquids at December 31, 2015:

NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Gal	Average		High		Low
2016
Price Swap Contracts	3,843,000	$	0.44	$	0.44	$	0.44

We had the following open financial basis swap contracts for natural gas at December 31, 2015:

BASIS SWAP DERIVATIVE CONTRACTS

						Weighted
						Average Spread
Volume in MMBtu	Reference Price 1  (1)	Reference Price 2  (1)	Period			($ per MMBtu)
4,125,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Apr ’16	—	Dec ’16	$	0.27
1,350,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Jan ’17	—	Mar ’17		0.25

(1)    The spread in these trades limits the differential of the settlement quotation prices for Tex/OKL Panhandle Eastern Pipeline (PEPL) inside FERC (IFERC) over NYMEX Henry Hub.

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NOTE 7 — ASSET RETIREMENT OBLIGATIONS

A summary of the changes in our asset retirement obligations is included in the table below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	62,872	$	56,023	$	48,593
Liabilities incurred		1,988		1,129		1,052
Liabilities assumed with acquired producing properties		—		3,002		5,480
Liabilities settled		(1,794)		(3,942)		(1,548)
Liabilities transferred in sales of properties		(3,149)		(1,886)		(606)
Revisions to estimates		(773)		6,348		919
Accretion expense		2,076		2,198		2,133
Balance, end of year		61,220		62,872		56,023
Less: Current portion		729		1,136		3,844
Long term portion	$	60,491	$	61,736	$	52,179

The total revisions included $1.5 million related to reductions to property, plant and equipment for the year ended December 31, 2015.  Total revisions included$2.9 millionand $0.4 million related to additions to property, plant and equipment for the years ended December 31,  2014, and 2013, respectively.

NOTE 8 — RELATED PARTY TRANSACTIONS

We have notes payable to our founder which bear interest at 10% with a balance of $25.7 million and $24.5 million at December 31, 2015 and 2014, respectively. See further information at Note 9.

Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received zero,$516,500, and $17,500of capital distributions from us during the years ended December 31, 2015, 2014 and 2013, respectively.

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2015, 2014 and 2013 were approximately $133,000,  $150,000 and $175,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

David McClure, our Vice President, Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $275,000,  $450,000 and $390,000 for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

David Pepper, one of our Landmen, and the cousin of our Vice President, Land and Business Development, David Murrell, received total compensation of $146,000,  $260,000 and $125,000 for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B partner, High Mesa, Inc. (“High Mesa”). We recorded $25.5 million in other receivable and $8.5 million in long term note receivable, while recording no gain or loss on the sale at December 31, 2014.  On January 2, 2015, the receivable of $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from Northwest Gas Processing, LLC (“NWGP”) to High Mesa Services, LLC, a subsidiary of High Mesa.  The Company believes the note to be fully collectible and accordingly has not recorded a reserve.  Interest

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income on the notes receivable from our affiliate amounted to $0.7 million during year ended December 31, 2015.  Such amounts have been added to the balance of the notes receivable.

On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million.  The receivables due from affiliate balance of $1.0 million as of December 31, 2015 includes the cost of repurchasing the land from NWGP.

During the year ended December 31, 2015, High Mesa, our Class B partner contributed $20 million to us.  For additional information, see Note 15- Partners’ Capital Deficit.

Alta Mesa is a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee.  For additional information on AEM, see Note 12.

NOTE 9 — LONG TERM DEBT

Long-term debt consists of the following:

	December 31,		December 31,
	2015		2014
	(in thousands)
Credit Facility	$	152,000	$	319,520
Senior Secured Term Loan		125,000		—
Senior Notes		448,598		448,088
Unamortized deferred financing costs		(7,823)		(6,466)
Total long-term debt	$	717,775	$	761,142
Notes payable to founder	$	25,748	$	24,540

Credit Facility. As of December 31, 2015, the Company had $152 million outstanding with $148 million of available borrowing capacity under the Sixth Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of banks.  On June 2, 2015, we entered into an Agreement and Amendment No. 11 (the “Eleventh Amendment”) to the credit facility.  The Eleventh Amendment, among other things, (i) redetermined and decreased the borrowing base from $375 million to $300 million, and (ii) extended the maturity date of the credit facility to October 13, 2017 from May 23, 2016.  The principal amount is payable at maturity.  On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the “Twelfth Amendment”) to amend the credit facility to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility.  As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million.  Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility.  The credit facility borrowing base is redetermined semi-annually on or about May 1 and November 1 of each year.  In November 2015, the lenders under the credit facility approved an increase in the borrowing base from $255 million to $300 million as part of the semi-annual redetermination.  The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 2.87% as of December 31, 2015 and 2.89% as of December 31, 2014.  The letters of credit outstanding as of December 31, 2015 and 2014 were $65,000 and $0.9million, respectively.

The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expense of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.   

As of December 31, 2015, we were in compliance with all covenants.  The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility when it is next redetermined.

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Subsequent to year end, on February 3, 2016, we entered into an Agreement and Amendment No. 13 to the credit facility (the “Thirteenth Amendment”). The Thirteenth Amendment, among other things: (a) permits us to enter into exchanges of outstanding senior notes for  a third lien term loan, (b) permits us to draw the remaining borrowing base availability under the credit facility into a controlled account with such funds not being treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, (c) permits us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (d) requires that twice a month we transfer available cash in excess of $25 million to the controlled account, and (e) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.00 to 1.00 to 4.50 to 1.00.

Senior Secured Term Loan.  On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “Term Loan Facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million.  The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of additional term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The net proceeds of approximately $121 million from the Term Loan Facility, after payment of transaction-related fees and expenses, were used to pay down outstanding amounts under our existing credit facility.  The Term Loan Facility matures on April 15, 2018. Theprincipal amount is payable at maturity.

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  PV-9 is calculated using four year NYMEX strip pricing adjusted for differentials.  Obligations under the Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and affiliates and are secured by second priority liens on substantially all of our subsidiaries assets that serve as collateral under the credit facility.  As of December 31, 2015, we were in compliance with all covenants of the Term Loan Facility.

We have the option to prepay all or a portion of the Term Loan Facility at any time. The Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, subject to a limited right to reinvest proceeds in capital expenditures, or an initial public offering. Such prepayments are subject to a premium of between 3% declining to 1% prior to the maturity date, and, if made prior to the first anniversary of the closing date, are also subject to a “make whole” premium to ensure that the lenders receive the total amount of interest that would have been paid from the date of prepayment to such first anniversary.

Subsequent to year end, on February 3, 2016, we entered into the first amendment to the Term Loan Facility (the “First Amendment”). The First Amendment: (a) permits us to enter into exchanges of outstanding senior notes for third lien term loan, (b) allows us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (c) requires that twice a month we transfer available cash in excess of $25 million to a controlled account, with such funds in the controlled account to not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, and (d) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.50 to 1.00 to 5.00 to 1.00.

Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility and the Term Loan Facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.4 million and $1.9 million at December 31, 2015 and December 31, 2014, respectively.

The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016, respectively. 

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $25.7 million and $24.5 million at December 31, 2015 and December 31, 2014, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021.  Interest and principal are payable at maturity. Our founder may convert the notesinto shares of our Class B partner’s, High Mesa, common stock upon certain conditions in the event of an initial public offering.

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These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 15, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.

Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2015, 2014, and 2013. Such amounts have been added to the balance of the founder notes.

Deferred financing costs. As of December 31, 2015, the Company had $9.0 million of deferred financing costs related to the credit facility, Term Loan Facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $7.8 million related to the Term Loan Facility and senior notes are included in long-term debt on the consolidated balance sheet as of December 31, 2015 in accordance with ASU 2015-03, which we adopted in the fourth quarter of 2015 (see Note 2 — Summary of Significant Accounting Policies). Deferred financing costs of $1.2 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2015. Amortization of deferred financing costs recorded for the years ended December 31, 2015, 2014 and 2013 was $3.4 million, $2.9 million and $2.8 million, respectively. These costs are included in interest expense on the consolidated statement of operations.

Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized discount, at December 31, 2015 are as follows (in thousands):

Year ending December 31,
2016	$	—
2017		152,000
2018		575,000
2019		—
2020		—
Thereafter		25,748
	$	752,748

The credit facility, Term Loan Facility and senior notes also contain restrictive covenantsthat limit our ability to, among other things, incur or guarantee additional debt, make distributions (except distributions equal to the amount of income tax liabilities), repay subordinated debt prior to its maturity, grant additional liens on our assets, enter into transactions with our affiliates, enter into hedging transactions with non-lender hedge counterparties, repurchase equity securities, make certain investments or acquisitions of substantially all or a portion of another entity’s business assets, and merge with another entity of dispose of any material assets.

The credit facility, Term Loan Facility and senior notes contain customary events of default.  If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. 

At December 31, 2015, we were in compliance with the covenants of our loan agreements. 

NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

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	December 31,		December 31,
	2015		2014
	(in thousands)
Capital expenditures	$	10,780	$	32,990
Revenues and royalties payable		5,082		7,302
Operating expenses/taxes		19,336		20,716
Interest		9,919		9,136
Compensation		5,434		10,586
Derivatives settlement payable		11,149		2,344
Other		1,201		261
Total accrued liabilities		62,901		83,335
Accounts payable		21,101		34,225
Accounts payable and accrued liabilities	$	84,002	$	117,560

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Contingencies

Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry.  Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource Company, LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive.  In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party.  On February 13, 2015, the case was dismissed by the U.S. District Judge. 

Environmental claims:  Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our consolidated financial statements at December 31, 2015.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  Management has established a liability for groundwater contamination in Florida of $1.3 million at December 31, 2015 and $1.1 million at December 31, 2014, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.

Performance appreciation rights:  In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial designated value (“SIDV”).  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of

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Index to Financial Statements

Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  Both the initial stipulated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors.  In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire. During 2015, we granted zero PARs and terminated 30,000 PARs with a SIDV of $40, resulting in 241,500 PARS issued at a weighted average value of $32.34.  Subsequent to year end, 360,000 PARs were issued with a SIDV of $40 and 3,500 PARs with a SIDV of $40 were terminated, resulting in 598,000 PARs issued at a weighted average value of $36.91.  We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan.  We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2015 and 2014.

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

Commitments

Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.Equipment leases are generally for four years or less. Rent expense, including office space and compressors, for the years ended December 31, 2015, 2014, and 2013 amounted to approximately $4.8 million, $5.7 million, and $5.3 million, respectively.

At December 31, 2015, future base rentals for non-cancelable operating leases are as follows (in thousands):

Year Ending December 31,
2016	$	4,130
2017		2,899
2018		1,574
2019		1,580
2020		1,593
Thereafter		2,827
	$	14,603

Additionally, at December 31, 2015, the Company had posted bonds in the aggregate amount of $24.4 million, primarily to cover future abandonment costs.

NOTE 12 — MAJOR CUSTOMERS

We sell our oil and natural gas primarily under a contract with AEM. We are a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee. Sales to AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015. During the second half of 2013 and throughout 2014 and 2015, we sold the majority of our production from operated fields to AEM. Production from non-operated fields, the most significant of which were our Eagleville oil field in South Texas and our Hilltop natural gas field in East Texas prior to their sale, was marketed on our behalf by the operators of those properties. Production from the Eagleville field was sold by Murphy Oil Corporation (“Murphy”), the operator of that property. Production from the Hilltop field was sold primarily by EnCana Oil & Gas (USA), Inc. (“EnCana”), the operator of a substantial portion of the wells in that field.

For the year ended December 31, 2015, revenues from AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities.  Based on revenues excluding hedging activities, no other major customer accounted for 10% or more of revenues.  For the year ended December 31, 2014, revenues from AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, one other major customer, Murphy accounted for 10% or more of revenues, with revenues excluding hedging activities of $61.2 million. For the year ended December 31, 2013, revenues from AEM were $61.3

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million, or 16% of total revenue excluding hedging activities. Based on revenues excluding hedging activities,  three other major customers accounted for 10% or more of those revenues individually, with contributions of $119.3 million (Murphy), $53.9 million (Shell Trading (US) Company), and $42.0 million (Plains Marketing and Transportation, Inc.)  We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available. 

NOTE 13 — 401(k) SAVINGS PLAN

Employees of Alta Mesa Services and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 50% of an employee’s salary deferral contribution up to a maximum of 8% of an employee’s salary. Matching contributions to the plan were approximately $710,000,  $683,000, and $585,000 for the years ended December 31, 2015, 2014, and 2013, respectively.

NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and 2015 and have declined dramatically since the second half of 2014.  Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves.  Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2016. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

NOTE 15 — PARTNERS’ CAPITAL (DEFICIT)

Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our sole Class B partner is High Mesa.  

On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our Board of Directors includes one member nominated by Highbridge and four members nominated by the Class A partners. 

Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the partnership agreement. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

Distribution and Income Allocation:In connection with the recapitalization on March 25, 2014, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until certain provisions are met.  After such provisions are met, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement.

The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility, Term Loan Facility, and our senior notes.

Net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.

For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. 

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NOTE 16 — SUBSEQUENT EVENTS

Drillco Contract

On January 13, 2016, our wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”) with BCE-STACK Development LLC (the “BCE”), to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches.

Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate (each, a “Joint Well”), provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well.

On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million. The terms and conditions are the same as those of the first two tranches.

Drawdown under Credit Facility

On March 16, 2016, we borrowed $141.9million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility.  As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the Administrative Agent.  Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account.  These funds are intended to be used for general corporate purposes.

Following the funding of this borrowing, the aggregate principal amount of borrowings under the credit facility was $300.0million, including $6.1million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.

NOTE 17 — SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes, Term Loan Facility and our credit facility.

Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.

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NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited)

Results of operations by quarter for the year ended December 31, 2015 were:

	Quarter Ended
2015	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	60,542	$	71,755	$	61,344	$	48,325
Income (loss) from operations (1)(2)		(95,077)		(23,881)		110,069		(60,592)
Net income (loss)	$	(109,211)	$	(39,509)	$	93,079	$	(76,152)

(1) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015.

(2) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively.

Results of operations by quarter for the year ended December 31, 2014 were:

	Quarter Ended
2014	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	103,432	$	115,590	$	125,644	$	87,462
Income (loss) from operations (3)(4)		71,461		(25,186)		73,025		35,873
Net income (loss)	$	56,893	$	(38,812)	$	59,326	$	21,793

(3) Includes $73.1 million and $18.3 million gain on sale of asset during the quarters ended March 31, 2014 and September 30, 2014, respectively.

(4) Includes $18.3 million, and $8.7 million of impairment expense during the quarters ended June 30, 2014 and September 30, 2014, respectively.

NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)

The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. 

Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

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Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2015, 2014, and 2013, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

	Oil	Gas	NGL's	BOE
	(MBbls)	(MMcf)	(MBbls)	(MBbls)
Total Proved Reserves:
Balance at December 31, 2012	20,620	152,489	5,695	51,731
Production	(2,897)	(16,664)	(398)	(6,072)
Purchases in place	1,462	1,265	—	1,673
Discoveries and extensions	14,541	29,012	1,969	21,345
Sales of reserves in place	(13)	(10,912)	—	(1,832)
Revisions of previous quantity estimates and other	(1,196)	(22,925)	(1,531)	(6,549)
Balance at December 31, 2013	32,517	132,265	5,735	60,296
Production	(3,770)	(14,449)	(537)	(6,715)
Purchases in place	610	327	—	665
Discoveries and extensions	13,281	28,822	4,119	22,204
Sales of reserves in place	(6,298)	(35,857)	(949)	(13,223)
Revisions of previous quantity estimates and other	(4,996)	(7,960)	20	(6,304)
Balance at December 31, 2014	31,344	103,148	8,388	56,923
Production	(4,203)	(11,900)	(678)	(6,865)
Discoveries and extensions	12,981	58,129	7,763	30,432
Sales of reserves in place	(6,544)	(8,250)	(748)	(8,667)
Revisions of previous quantity estimates and other	564	14,296	3,712	6,660
Balance at December 31, 2015	34,142	155,423	18,437	78,483
Proved Developed Reserves:
Balance at December 31, 2013	16,335	92,640	3,138	34,913
Balance at December 31, 2014	15,182	63,334	4,028	29,765
Balance at December 31, 2015	14,942	71,752	6,958	33,859
Proved Undeveloped Reserves:
Balance at December 31, 2013	16,182	39,625	2,597	25,383
Balance at December 31, 2014	16,162	39,814	4,360	27,158
Balance at December 31, 2015	19,200	83,671	11,479	44,624

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

	December 31,
	2015		2014
	(in thousands)
Capitalized costs:
Proved properties	$	1,345,482	$	1,417,785
Unproved properties		127,551		84,620
Total		1,473,033		1,502,405
Accumulated depreciation, depletion, amortization and impairment		(947,091)		(816,229)
Net capitalized costs	$	525,942	$	686,176

Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical

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costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Costs incurred during the year:
Property acquisition costs
Unproved (1)	$	74,475	$	33,787	$	34,884
Proved (2)		2,899		7,462		35,954
Exploration		34,275		59,201		55,300
Development (3)		146,299		341,594		242,912
	$	257,948	$	442,044	$	369,050

(1) Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million.

(2) Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. 

(3) Includes asset retirement additions (revisions) of ($0.3) million, $4.5 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Standardized Measure of Discounted Future Net Cash Flows

The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Future cash inflows as of December 31, 2015 and 2014 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2015, 2014, and 2013:

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Future cash flows	$	2,395,128	$	3,737,412	$	3,959,938
Future production costs		(860,600)		(991,149)		(1,146,123)
Future development costs		(403,953)		(450,659)		(474,191)
Future taxes on income		—		—		—
Future net cash flows		1,130,575		2,295,604		2,339,624
Discount to present value at 10 percent per annum		(500,979)		(877,558)		(933,350)
Standardized measure of discounted future net cash flows	$	629,596	$	1,418,046	$	1,406,274
Base price for crude oil, per Bbl, in the above computation was:	$	50.28	$	94.99	$	96.78
Base price for natural gas, per Mcf, in the above computation was:	$	2.58	$	4.35	$	3.67

No consideration was given to the Company’s hedged transactions.

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Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in standardized measure of discounted future net cash flows:

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Balance at beginning of year	$	1,418,046	$	1,406,274	$	914,421
Sales of oil and natural gas, net of production costs		(147,906)		(320,130)		(263,952)
Changes in sales and transfer prices, net of production costs		(823,073)		(153,770)		69,609
Revisions of previous quantity estimates		53,101		(477,377)		(150,634)
Purchases of reserves-in-place		—		21,633		93,877
Sales of reserves-in-place		(244,251)		(107,414)		(11,193)
Current year discoveries and extensions		260,078		701,820		621,832
Changes in estimated future development costs		4,376		2,591		11,623
Development costs incurred during the year		42,420		161,357		75,973
Accretion of discount		141,805		140,627		91,442
Net change in income taxes		—		—		—
Change in production rate (timing) and other		(75,000)		42,435		(46,724)
Net change		(788,450)		11,772		491,853
Balance at end of year	$	629,596	$	1,418,046	$	1,406,274

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EX-21.1

EXHIBIT 21.1

ALTA MESA HOLDINGS, LP

Subsidiaries

Subsidiary		Jurisdiction of Formation
1.	Alabama Energy Resources, LLC	Texas
2.	Alta Mesa Acquisition Sub, LLC	Texas
3.	Alta Mesa Drilling, LLC	Texas
4.	Alta Mesa Energy LLC	Texas
5.	Alta Mesa Finance Services Corp.	Delaware
6.	Alta Mesa GP, LLC	Texas
7.	Alta Mesa Services, LP	Texas
8.	AM Idaho LLC	Texas
9.	AM Michigan LLC	Texas
10.	AMH Energy New Mexico, LLC	Texas
11.	Aransas Resources, L.P.	Texas
12.	ARI Development, LLC	Delaware
13.	Brayton Management GP II, LLC	Texas
14.	Brayton Management GP, LLC	Texas
15.	Brayton Resources II, L.P.	Texas
16.	Brayton Resources, L.P.	Texas
17.	Buckeye Production Company, LP	Texas
18.	Cairn Energy USA, LLC	Delaware
19.	FBB Anadarko, LLC	Delaware
20.	Galveston Bay Resources, LP	Texas
21.	LEADS Resources, L.L.C.	Texas
22.	Louisiana Exploration & Acquisition Partnership, LLC	Delaware
23.	Louisiana Exploration & Acquisitions, LP	Texas
24.	Louisiana Onshore Properties LLC	Delaware
25.	Navasota Resources, Ltd., LLP	Texas
26.	New Exploration Technologies Company, L.L.C.	Texas
27.	Nueces Resources, LP	Texas
28.	Oklahoma Energy Acquisitions, LP	Texas
29.	Orion Operating Company, LP	Texas
30.	Petro Acquisitions, LP	Texas
31.	Petro Operating Company, LP	Texas
32.	Sundance Acquisition, LLC	Texas
33.	TEA Energy Services, LLC	Texas
34.	TE TMR, LLC	Texas
35.	Texas Energy Acquisitions, LP	Texas
36.	The Meridian Production, LLC	Texas
37.	The Meridian Resource & Exploration LLC	Delaware
38.	The Meridian Resource, LLC	Delaware
39.	TMR Drilling, LLC	Texas
40.	TMR Equipment, LLC	Texas
41.	Virginia Oil and Gas, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Petroleum Engineers and Geoscientists

We consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our audit letter as of December 31, 2015, included in the Annual Report on Form 10-K of Alta Mesa Holdings, LP for the year ended December 31, 2015, as well as in the notes to the financial statement included therein.

?

 /s/ RYDER SCOTT COMPANY, LP.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 29,  2016

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Harlan H. Chappelle, certify that:

1.I have reviewed this Annual Report on Form 10-K of Alta Mesa Holdings, LP;

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 Alta Mesa Holdings, LP 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 Alta Mesa Holdings, LP 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 Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: March 29, 2016

/s/ Harlan H. Chappelle

Harlan H. Chappelle

President and Chief Executive Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Michael A. McCabe, certify that:

1.I have reviewed this Annual Report on Form 10-K of Alta Mesa Holdings, LP;

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 Alta Mesa Holdings, LP 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 Alta Mesa Holdings, LP 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 Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’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 Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: March 29, 2016

/s/ Michael A. McCabe

Michael A. McCabe

Vice President and Chief Financial Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF ALTA MESA HOLDINGS, LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Annual Report on Form 10-K of Alta Mesa Holdings, LP for the period ended December 31, 2015, I, Harlan H. Chappelle, President and Chief Executive Officer of Alta Mesa Holdings, LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Annual Report on Form 10-K for the period ended December 31, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Annual Report on Form 10-K for the period ended December 31, 2015 fairly presents, in all material respects, the financial condition and results of operations of Alta Mesa Holdings, LP for the periods presented therein.

Date: March 29, 2016

/s/ Harlan H. Chappelle

Harlan H. Chappelle

President and Chief Executive Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF ALTA MESA HOLDINGS, LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Annual Report on Form 10-K of Alta Mesa Holdings, LP for the period ended December 31, 2015, I, Michael A. McCabe, Chief Financial Officer of Alta Mesa Holdings, LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Annual Report on Form 10-K for the period ended December 31, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Annual Report on Form 10-K for the period ended December 31, 2015 fairly presents, in all material respects, the financial condition and results of operations of Alta Mesa Holdings, LP for the periods presented therein.

Date: March 29, 2016

/s/ Michael A. McCabe

Michael A. McCabe

Vice President and Chief Financial Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-99.1

Exhibit 99.1

ALTA MESA HOLDINGS, L.P.

Estimated

Future Reserves

Attributable to CertainLeasehold and Royalty Interests

SEC Parameters

As of

December 31, 2015

/s/ Kevin E. Gangluff

Kevin E. Gangluff, P.E.

TBPE License No. 75852

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

March 24,  2016

Alta Mesa Holdings, L.P.

15021 Katy Freeway, Suite 400

Houston, TX 77094

Gentlemen:

At the request of Alta Mesa Holdings, L.P. (Alta Mesa), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2015prepared byAlta Mesa’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).Our reserves audit, completed in early March2016 and presented herein, was prepared for public disclosure by Alta Mesa in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.  The estimated reserves shown herein representAlta Mesa’s estimated net reserves attributable to the leaseholdand royalty interests  in certain properties owned by Alta Mesa and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2015.The properties reviewed by Ryder Scott incorporate409 reserve determinations and are located in the states ofIdaho, Louisiana, Oklahoma,Texas, and West Virginia.

The properties reviewed by Ryder Scott account for a portion of Alta Mesa’s total net proved reserves as of December 31, 2015.  Based on the estimates of total net proved reserves prepared by Alta Mesa, the reserves audit conducted by Ryder Scott addresses 96 percent of the total proved developed net liquid hydrocarbon reserves, 91  percent of the total proved developed net gas reserves, in excess of 99 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 99 percent of the total proved undeveloped net gas reserves of Alta Mesa. The properties reviewed by Ryder Scott account for a portion of Alta Mesa’s total proved discounted future net income using SEC hydrocarbon price parameters as of December 31,  2015.  Based on the reserve and income projections prepared by Alta Mesa, the audit conducted by Ryder Scott addresses 109 percent of the total proved developed discounted future net income and in excess of 99percent of the total proved undeveloped  discounted future net income of Alta Mesa.  The high percentage of audit coverage of the associated proved developed discounted future net income is the result of the “not reviewed” properties having a negative discounted future net income primarily due to future abandonment liabilities and near term operating expenses associated with properties with no reserves.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Alta Mesa, it is our opinion that the overall procedures and methodologies utilized by Alta Mesa in preparing their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Alta Mesa are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 2

The estimated reserves and future net income amounts presented in this report are related to hydrocarbon prices.  Alta Mesa has informed us that in the preparation of their reserve and income projections, as of December 31, 2015, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The net reserves as estimated by Alta Mesa attributable to Alta Mesa's interestin properties that we reviewed and the reserves of properties that we did not review are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Alta MesaHoldings, L.P.

As of December 31, 2015

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Reserves of Properties Auditedby Ryder Scott
Oil/Condensate – MBarrels	12,120	2,011	19,157	33,288
Plant Products - MBarrels	6,853	17	11,453	18,323
Gas – MMCF	63,282	2,140	83,017	148,439
Net Reserves of Properties Not Audited byRyder Scott
Oil/Condensate – MBarrels	258	553	43	854
Plant Products –MBarrels	20	68	26	114
Gas – MMCF	1,129	5,201	654	6,984
Total Net Reserves
Oil/Condensate – MBarrels	12,378	2,564	19,200	34,142
Plant Products – MBarrels	6,873	85	11,479	18,437
Gas – MMCF	64,411	7,341	83,671	155,423

Liquid hydrocarbons are expressed in standard 42 gallon barrels.  All gas volumes are reported on an “assold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  The term Mbarrels denotes 1000’s of barrels.

In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant.  The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas.  Alta Mesa has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 3

Because it was beyond the scope of this audit, Ryder Scott has not conducted an economic analysis to evaluate the net economic benefit from the production of the above reserves volumes. Thus, Alta Mesa’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance.  The total future net income discounted at 10 percent prepared by Alta Mesa (which Ryder Scott did not review) attributable to Alta Mesa's interest in properties that we reviewed and those properties that we did not review are summarized below:

SEC PARAMETERS

Discounted Future Net Income

Certain Leasehold and Royalty Interests of

Alta Mesa Holdings, L.P.

As of December 31, 2015

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Future Net Income Discounted at 10% ($M)
Properties Reviewed by      Ryder Scott	366,972	46,275	250,340	663,587
Properties Not Reviewed by      Ryder Scott	(43,700)	9,036	673	(33,991)
Total	323,272	55,311	251,013	629,596

The discounted future net income shown above is presented at Alta Mesa’s request for your information and should not be construed as an estimate of fair market value.  The term $M denotes thousands of dollars.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status and Definitions Guidelines” in this report.  The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote

Alta Mesa Holdings, L.P.

March 24, 2016

Page 4

progressively increasing uncertainty in their recoverability.  At Alta Mesa’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas 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.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts. 

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy.  These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “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.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 5

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves prepared by Alta Mesa, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods.  Approximately 69percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods.  These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available Septemberthrough December2015, in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Alta Mesa or obtained from public data sources and were considered sufficient for the purpose thereof.  Approximately 27percent of the proved producing reserves that we reviewed were estimated by the analogy method.  The remaining 4 percent of the proved producing reserves were estimated by the volumetric method.  These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 70percent of the proved developed non-producing reserves that we reviewed were estimated by the volumetric method.  Approximately 30 percent of the developed non-producing reserves that we reviewed were estimated by past performance or analogy.  Approximately 94percent of the proved undeveloped reserves that we reviewed were estimated by analogy.  The remaining 6percent was estimated by the volumetric method or a combination of methods.  The volumetric analysis utilized pertinent well and geoscience data furnished to Ryder Scott by Alta Mesafor our review or which we have obtained from public data sources that were available Septemberthrough December 2015.  The data utilized from the analogues in conjunction with well and geoscience data incorporated into the volumetric analysis were considered sufficient for the purpose thereof. 

Horizontal wells and locations,essentially all of which are located in the Mississippi Lime,  Meramec,and Oswego plays in Oklahoma, represent 82 percent of Alta Mesa’s liquids reserves and80 percent of Alta Mesa’s gas reserves.  Sixty-six percent of liquids reserves and 64 percent of gas reserves associated with horizontal drilling are proved undeveloped.  The remainder are producing.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  To confirm that the proved reserves reviewed

Alta Mesa Holdings, L.P.

March 24, 2016

Page 6

by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Alta Mesa relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Alta Mesafor the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31,  2015for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used by Alta Mesa for the geographic area reviewed by us.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Alta Mesa to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.”  The differentials used by Alta Mesawere accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa.   

The table below summarizes Alta Mesa’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Alta Mesa’s “average realized prices.”  The average realized prices shown in the table below were determined from Alta Mesa’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Alta Mesa’s estimate of the total net reserves for the properties reviewed by us for the geographic area.  The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average BenchmarkPrices	Average RealizedPrices
United States	Oil/Condensate	WTI Cushing	$50.28/Bbl	$49.79/Bbl
	NGLs	WTI Cushing	$50.28/Bbl	$16.77/Bbl
	Gas	Henry Hub	$2.58/MMBTU	$2.48/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Alta Mesa’s individual property evaluations. 

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed.  In certain cases, the gas volumes presented herein include gas consumed in operations as reserves.  In those cases, the effective price was reduced such that the fuel used had no value.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 7

Operating costs furnished by Alta Mesa are based on the operating expense reports of Alta Mesa and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements.The operating costs furnished by Alta Mesa were accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa.No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Alta Mesa are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished by Alta Mesa were accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa.  The estimated net cost of abandonment after salvage was included by Alta Mesa for properties where abandonment costs net of salvage were significant.  Alta Mesa’s estimates of the net abandonment costs were accepted without independent verification. 

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Alta Mesa’s plans to develop these reserves as of December 31,  2015.  The implementation of Alta Mesa’s development plans as presented to us is subject to the approval process adopted by Alta Mesa’s management.  As the result of our inquiries during the course of our review, Alta Mesa has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Alta Mesa’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Alta Mesa.  Alta Mesa has provided written documentation stating their commitment to proceed with the development activities as presented to us.   Additionally, Alta Mesa has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.  While these plans could change from those under existing economic conditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Alta Mesa were held constant throughout the life of the properties.

Alta Mesa’s forecasts of future production rates are based on historical performance from wells currently on production.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates. 

Test data and other related information were used by Alta Mesato estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Alta Mesa.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in Alta Mesa’s estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 

Alta Mesa Holdings, L.P.

March 24, 2016

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The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. 

Alta Mesa’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Alta Mesaowns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Alta Mesafor potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Alta Mesa are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties.  These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner.  We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Alta Mesa has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In performing our audit of Alta Mesa’s forecast of future proved production, we have relied upon data furnished by Alta Mesa with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Alta Mesa.  We consider the factual data furnished to us by Alta Mesa to be appropriate and sufficient for the purpose of our review of Alta Mesa’s estimates of reserves.  In summary, we consider the assumptions, data, methods and analytical procedures used by Alta Mesa and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 9

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Alta Mesa, it is our opinion that the overall procedures and methodologies utilized by Alta Mesa in preparing their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Alta Mesa are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Alta Mesa's estimates of proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance between Alta Mesa's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Alta Mesa when its reserve estimates were prepared.  In these cases, Alta Mesa revised its estimates to better conform to our estimates. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reservesowned by Alta Mesa.

Other Properties

Other properties, as used herein, are those properties of Alta Mesa which we did not review.  The proved net reserves attributable to the other properties account forapproximately 2percent of the total proved netliquid hydrocarbon reserves,approximately 5percent of the total proved net gas reserves, and approximately negative 5 percent of the future net income discounted at 10 percentbased on estimates prepared by Alta Mesa as of December 31,  2015.

The same technical personnel of Alta Mesa were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

Alta Mesa Holdings, L.P.

March 24, 2016

Page 10

We are independent petroleum engineers with respect to Alta Mesa.  Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Alta Mesa.  

We have provided Alta Mesa with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Alta Mesa and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Kevin E. Gangluff

Kevin E. Gangluff, P.E.

TBPE License No. 75852

Senior Vice President

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Kevin E. Gangluff is the primary technical person responsible for overseeing the estimate of the reserves, future production and income in this report.

Mr. Gangluff, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, is a Senior Vice President and serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies throughout North America.  Before joining Ryder Scott, Mr. Gangluff served in a number of managerial, supervisory, and engineering positions with Exxon Corporation (now ExxonMobil Corporation), Texas Oil & Gas Corp., and Gruy Engineering Corp.

Mr. Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin.  Mr. Gangluff is a licensed Professional Engineer in the State of Texas.  He is a member of the Society of Petroleum Engineers, the Texas Independent Producers and Royalty Owners Association, and the Houston Producers Forum.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gangluff fulfills.

Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. 

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.  Proved oil and gas 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not  started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production. 

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2015 USD ($) shares
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	0001518403
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding | shares	0
Entity Public Float | $	$ 0
Entity Current Reporting Status	No
Entity Voluntary Filers	Yes
Entity Well-known Seasoned Issuer	No

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 8,869	$ 1,349
Restricted cash	105	23,793
Accounts receivable, net of allowance of $1,402 and $1,449, respectively	27,111	43,581
Other receivables	18,526	8,238
Receivable due from affiliate	1,053	25,500
Prepaid expenses and other current assets	4,774	2,132
Derivative financial instruments	62,631	59,803
Total current assets	123,069	164,396
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	525,942	686,176
Other property and equipment, net	11,097	11,505
Total property and equipment, net	537,039	697,681
OTHER ASSETS
Long-term restricted cash		900
Investment in LLC - cost	9,000	9,000
Deferred financing costs, net	1,199	1,634
Notes receivable due from affiliate	9,213	8,500
Advances to operators	37	619
Deposits and other assets	1,333	1,124
Derivative financial instruments	41,635	27,271
Total other assets	62,417	49,048
TOTAL ASSETS	722,525	911,125
CURRENT LIABILITIES
Accounts payable and accrued liabilities	84,002	117,560
Current portion, asset retirement obligations	729	1,136
Total current liabilities	84,731	118,696
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	60,491	61,736
Long-term debt	717,775	761,142
Notes payable to founder	25,748	24,540
Other long-term liabilities	10,829	6,457
Total long-term liabilities	814,843	853,875
TOTAL LIABILITIES	$ 899,574	$ 972,571
Commitments and Contingencies (Note 11)
PARTNERS' DEFICIT	$ (177,049)	$ (61,446)
TOTAL LIABILITIES AND PARTNERS' DEFICIT	$ 722,525	$ 911,125

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts	$ 1,402	$ 1,449

XML

Consolidated Statements Of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES AND OTHER
Oil	$ 199,799	$ 347,842	$ 297,836
Natural gas	30,621	65,002	61,350
Natural gas liquids	10,864	18,281	15,264
Other revenues	682	1,003	1,207
Total operating revenues	241,966	432,128	375,657
Gain (loss) on sale of assets	67,781	87,520	(2,715)
Gain (loss) on derivative contracts	124,141	96,559	(17,150)
Total operating revenues and other	433,888	616,207	355,792
OPERATING EXPENSES
Lease and plant operating expense	71,736	73,820	70,450
Production and ad valorem taxes	15,131	28,214	26,369
Workover expense	6,511	8,961	13,679
Exploration expense	42,718	61,912	33,065
Depreciation, depletion, and amortization expense	143,969	141,804	118,558
Impairment expense	176,774	74,927	143,166
Accretion expense	2,076	2,198	2,133
General and administrative expense	44,454	69,198	47,023
Total operating expenses	503,369	461,034	454,443
INCOME (LOSS) FROM OPERATIONS	(69,481)	155,173	(98,651)
OTHER INCOME (EXPENSE)
Interest expense	(62,473)	(55,812)	(55,188)
Interest income	723	15	124
Total other income (expense)	(61,750)	(55,797)	(55,064)
INCOME (LOSS) BEFORE STATE INCOME TAXES	(131,231)	99,376	(153,715)
(Provision) for state income taxes	(562)	(176)
NET INCOME (LOSS)	$ (131,793)	$ 99,200	$ (153,715)

XML

Consolidated Statements Of Changes In Partners' Capital (Deficit) $ in Thousands	USD ($)
Balance, Beginning at Dec. 31, 2012	$ (6,368)
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract]
Distributions	(24)
Net income (loss)	(153,715)
Balance, Ending at Dec. 31, 2013	(160,107)
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract]
Distributions	(539)
Net income (loss)	99,200
Balance, Ending at Dec. 31, 2014	(61,446)
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract]
Contributions	20,000
Distributions	(3,810)
Net income (loss)	(131,793)
Balance, Ending at Dec. 31, 2015	$ (177,049)

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (131,793)	$ 99,200	$ (153,715)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense	143,969	141,804	118,558
Impairment expense	176,774	74,927	143,166
Accretion expense	2,076	2,198	2,133
Amortization of loan costs	3,392	2,885	2,839
Amortization of debt discount	510	510	510
Dry hole expense	22,708	30,294	15,295
Expired leases	6,526	4,319	3,289
(Gain) loss on derivative contracts	(124,141)	(96,559)	17,150
Settlements of derivative contracts	106,949	9,493	18,177
Interest converted into debt	1,208	1,209	1,208
Interest on notes receivable due from affiliate	(713)
(Gain) loss on sale of assets	(67,781)	(87,520)	2,715
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture		(106)	2,305
Accounts receivable	16,470	(95)	(2,771)
Other receivables	(10,288)	(5,686)	1,863
Receivable due from affiliate	(1,725)
Prepaid expenses and other non-current assets	(2,269)	7,251	4,477
Settlement of asset retirement obligation	(1,794)	(3,942)	(1,548)
Accounts payable, accrued liabilities, and other long-term liabilities	3,900	4,702	(3,132)
NET CASH PROVIDED BY OPERATING ACTIVITIES	143,978	184,884	172,519
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(223,604)	(366,090)	(311,438)
Acquisitions	(48,202)	(18,110)	(51,377)
Proceeds from sale of property	141,404	177,476	26,668
Proceeds from property divesture classified as restricted cash		41,590
Investment in restricted cash related to property divestitures	24,587	(24,587)
NET CASH USED IN INVESTING ACTIVITIES	(105,815)	(189,721)	(336,147)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	252,500	169,500	214,500
Repayments of long-term debt	(295,020)	(169,270)	(50,000)
Additions to deferred financing costs	(4,313)	(42)	(97)
Capital distributions	(3,810)	(539)	(24)
Capital contributions	20,000
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(30,643)	(351)	164,379
NET INCREASE IN CASH AND CASH EQUIVALENTS	7,520	(5,188)	751
CASH AND CASH EQUIVALENTS, beginning of period	1,349	6,537	5,786
CASH AND CASH EQUIVALENTS, end of period	8,869	1,349	6,537
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	56,579	51,219	50,731
Cash paid (received) during the period for state taxes	751	(123)	18
Change in asset retirement obligations	487	2,643	854
Asset retirement obligations assumed, purchased properties		3,002	5,480
Change in accruals or liabilities for capital expenditures	(34,160)	23,858	$ (14,085)
Non-cash divestiture of oil and gas properties		$ (34,000)
Non-cash acquisition of property and land	$ 2,473

XML

Nature Of Operations

12 Months Ended

Dec. 31, 2015

Description Of Business [Abstract]

Description Of Business

NOTE 1 — NATURE OF OPERATIONS

Nature of Operations.  Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our core properties are located in Oklahoma and Louisiana.

XML

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”).  Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ deficit.

Principles of Consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

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 reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash.The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2015, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute.  As of December 31, 2014, the Company had $24.6 million of proceeds remaining in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code from the sale of our Hilltop field Deep Bossier properties. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions, and in March 2015, the remaining $23.7 million of restricted cash was returned to us to be used for general corporate purposes and, as such, was classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014.  The Company planned to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures.

Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized.  Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $9.8 million and $10.3 million at December 31, 2015 and 2014, respectively.  Trade receivables from the sale of oil and natural gas were $17.9 million and $35.1 million at December 31, 2015 and 2014, respectively.  See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC (“AEM”).  Accounts receivable from AEM were $12.6 million and $16.6 million as of December 31, 2015 and 2014, respectively.

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.

Deferred Financing Costs.The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

In the fourth quarter of 2015, the Company adopted Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs.  In accordance with the new guidance, deferred financing costs related to the Company’s senior unsecured notes and Term Loan Facility (as defined in Note 9), which had been included in deferred financing costs, net under other assets on the consolidated balance sheets prior to the adoption of ASU 2015-03, are now included in long-term debt on the consolidated balance sheets, resulting in decreases in both deferred financing costs, net and long-term debt of $7.8 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual period presented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the consolidated balance sheet as of December 31, 2014 included a deduction for deferred financing costs of $6.5 million in long-term debt, which had previously been presented in deferred financing costs, net under other assets. Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

Property and Equipment. Oil and natural 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 leases are recorded as unproved properties 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. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet 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. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. 

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas 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.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or 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 at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Our evaluation of the Company’s proved properties resulted in impairment expense of $172.0 million,$72.9 million and $135.2 million for the years ended December 31, 2015, 2014, and 2013, respectively, primarily due to lower forecasted commodity prices.

Unproved properties 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 properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2015, 2014 and 2013, impairment expense of unproved properties was $4.8 million, $2.0 million, and $8.0 million, respectively.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2015, 2014, and 2013, respectively, the Company did not record any impairment expense related to other long-lived assets.

Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. 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 lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

DD&A expense for the years ended December 31, 2015, 2014, and 2013 related to oil and natural gas properties was $140.9 million, $139.0 million, and $115.5 million, respectively.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2015, 2014, and 2013 was $3.0 million, $2.8 million, and $3.1 million respectively.

Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.

Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.  Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows. 

Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “ Provision for state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

We have considered our exposure under the standard at both the federal and state tax levels.  We have not recorded any liabilities for uncertain tax positions as of December 31, 2015 and 2014. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2015,  2014, or 2013.  

The Company’s tax returns for the years ended December 31, 2012 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed.

Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk.  The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.  We have estimated the fair value of our $450 million senior notes payable at $162 million on December 31, 2015. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 5 – Fair value disclosures and Note 9 - Long-term debt.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”).  ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach. 

In September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

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Significant Acquisition And Divestitures

12 Months Ended

Dec. 31, 2015

Significant Acquisition and Divestitures [Abstract]

Significant Acquisition and Divestitures

NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

2015 Activity

Alta Mesa Eagle, LLC Divestiture

On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”).  AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas.  In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area.  The effective date of the transaction (the “Effective Date”) is July 1, 2015.  

The aggregate cash purchase price for the Membership Interests was $125 million subject to certain adjustments, consisting of $118 million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received.  The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date.  As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million.  Cash received was utilized to pay down borrowings under our credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.

The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118.5 million in pre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below. 

Kingfisher Leasehold Acquisition

On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma.  The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments.  The effective date of the acquisition was April 1, 2015.  The purchase was funded with borrowings under our credit facility.  

2014 Activity

Eagleville Divestiture

On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The initial cash purchase price was $173 million, subsequently adjusted to approximately $171 million for settlement adjustments.  The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date.  As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE.  We recorded a gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained.

The sold portion of Eagleville field contributed approximately $11.1 million in the first quarter of 2014, prior to its sale. The sold portion of Eagleville field contributed approximately $47.0 million in net pre-tax profit for the year ended December 31, 2013.

Hilltop Divestiture

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a gain on the sale of $15.9 million.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.

The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014.

2013 Activity

Hilltop Divestiture

On October 2, 2013, we closed the sale of certain of our properties in East Texas, comprising a portion of our Hilltop field. The properties sold were primarily producers of dry natural gas located in Leon County, Texas. As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2 BCFE. The cash purchase price was approximately $19 million (net of costs of the sale).  There was no material gain on the sale.  The Hilltop interests contributed approximately $6.9 million in net pre-tax loss during the year ended December 31, 2013.

Weeks Island Acquisition

On October 1, 2013, we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $42 million plus related abandonment costs. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 million BOE as of the effective date of July 1, 2013.  

A summary of the consideration paid and the allocation of the purchase prices are as follows:

	October 1,
	2013
	(in thousands)
Summary of Consideration
Cash	$	41,841
Fair value of asset retirement obligations assumed		5,311
Total	$	47,152
Summary of Purchase Price Allocation
Proved oil and natural gas properties	$	30,279
Unproved oil and natural gas properties		16,873
Total	$	47,152

The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from the date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2013, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods. 

	Total		Income
	Revenue		(Loss)
	(in thousands)
Actual results of Stone included in our statement of operations for the period October 1, 2013
through December 31, 2013	$	10,509	$	8,575
Pro forma results for the combined entity for the year ended December 31, 2013	$	376,063	$	(146,866)

Other

During 2013, we sold our drilling rig for a cash purchase price of approximately $7.0 million and recorded a loss on sale of approximately $1.2 million.

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Property And Equipment

12 Months Ended

Dec. 31, 2015

Property And Equipment [Abstract]

Property And Equipment

NOTE 4 — PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	December 31,		December 31,
	2015		2014
	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	127,551	$	84,620
Accumulated impairment		(2,684)		(3,749)
Unproved properties, net		124,867		80,871
Proved oil and natural gas properties		1,345,482		1,417,785
Accumulated depreciation, depletion, amortization and impairment		(944,407)		(812,480)
Proved oil and natural gas properties, net		401,075		605,305
TOTAL OIL AND NATURAL GAS PROPERTIES, net		525,942		686,176
LAND		3,868		2,820
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		18,794		17,302
Accumulated depreciation		(11,565)		(8,617)
OTHER PROPERTY AND EQUIPMENT, net		7,229		8,685
TOTAL PROPERTY AND EQUIPMENT, net	$	537,039	$	697,681

Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well costs during2015,2014, and2013. The table does not include amounts that were capitalized and either subsequently expensed within the same year.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	13,301	$	20,317	$	3,863
Additions to capitalized well costs pending determination of proved reserves		4,364		15,870		21,387
Reclassifications to proved properties		(8,583)		(6,593)		(4,933)
Capitalized exploratory well costs charged to expense		(3,076)		(16,293)		—
Balance, end of year	$	6,006	$	13,301	$	20,317

The ending balance in capitalized exploratory well costs includes the costs of six wells primarily in two prospects that were capitalized for periods greater than one year at December 31, 2015.  We have capitalized $3.0 million and $2.2 million of exploratory well costs covering periods greater than one year at December 31, 2015 and 2014.

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Fair Value Disclosures

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Disclosures

NOTE 5 — FAIR VALUE DISCLOSURES

The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (NYMEX) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2.

Our senior notes are carried at historical cost, net of unamortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.

Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $499.6 million were written down to their fair value of $322.8 million, resulting in an impairment charge of $176.8 million for the year ended December 31, 2015. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. Oil and natural gas properties with a carrying amount of $237.2 million were written down to their fair value of $94.0 million, resulting in an impairment charge of $143.2 million for the year ended December 31, 2013. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

In connection with the Stone acquisition in 2013, we recorded oil and natural gas properties with a fair value of $47.2 million.  Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015.  We recorded a total of $4.1 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2014.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

	Level 1		Level 2		Level 3		Total
		(in thousands)
At December 31, 2015:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	166,106		—	$	166,106
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	61,840		—	$	61,840
At December 31, 2014:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	140,652		—	$	140,652
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	53,578		—	$	53,578

The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.

For additional information on derivative contracts, see Note 6.

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month.  The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly.No derivative contracts have been entered into for trading purposes.

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets.  Likewise, derivative (liabilities) could be presented in an asset account.

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2015	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	86,000	$	(23,369)	$	62,631
Derivative financial instruments, long-term assets		80,106		(38,471)		41,635
Total	$	166,106	$	(61,840)	$	104,266

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2015	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	23,369	$	(23,369)	$	—
Derivative financial instruments, long-term liabilities		38,471		(38,471)		—
Total	$	61,840	$	(61,840)	$	—

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2014	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	91,341	$	(31,538)	$	59,803
Derivative financial instruments, long-term assets		55,325		(28,054)		27,271
Total	$	146,666	$	(59,592)	$	87,074

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2014	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	31,538	$	(31,538)	$	—
Derivative financial instruments, long-term liabilities		28,054		(28,054)		—
Total	$	59,592	$	(59,592)	$	—

The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

Derivatives not
designated as hedging	Location of	Year Ended December 31,
instruments under ASC 815	Gain (Loss)	2015		2014		2013
		(in thousands)
Oil commodity contracts	Gain (loss) on derivative contracts	$	113,295	$	82,510	$	(17,715)
Natural gas commodity contracts	Gain on derivative contracts		10,712		14,049		565
Natural gas liquids commodity contracts	Gain on derivative contracts		134		—		—
Total gains (losses) from
derivatives not designated as hedges		$	124,141	$	96,559	$	(17,150)

Other receivables includes$17.5 million and $8.0 million of derivative positions settled, but not yet received as of December 31, 2015 and 2014, respectively.  

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

We had the following open derivative contracts for crude oil at December 31, 2015:  

OIL DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2016
Price Swap Contracts	2,532,300	$	64.16	$	94.92	$	53.00
Collar Contracts
Short Call Options	739,100		99.69		130.00		75.00
Long Put Options	603,800		63.71		95.00		40.55
Short Put Options	420,800		72.81		75.00		65.00
2017
Collar Contracts
Short Call Options	1,960,150		85.02		113.83		62.50
Long Put Options	1,412,650		72.27		90.00		60.00
Short Put Options	1,412,650		54.63		70.00		45.00
2018
Collar Contracts
Short Call Options	1,183,000		80.51		104.65		72.00
Long Put Options	1,183,000		67.05		80.00		62.50
Short Put Options	1,183,000		48.90		60.00		45.00
2019
Collar Contracts
Short Call Options	821,250		75.17		75.70		74.50
Long Put Options	821,250		62.50		62.50		62.50
Short Put Options	821,250		45.00		45.00		45.00

We had the following open derivative contracts for natural gas at December 31, 2015:  

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2016
Price Swap Contracts	7,320,000	$	3.05	$	3.17	$	2.95
Collar Contracts
Short Call Options	1,510,000		2.40		2.40		2.40
Long Put Options	1,510,000		2.25		2.25		2.25
2017
Collar Contracts
Short Call Options	6,570,000		5.00		5.00		4.98
Long Put Options	6,570,000		4.50		4.50		4.50
Short Put Options	6,570,000		4.00		4.00		4.00
2018
Collar Contracts
Short Call Options	5,475,000		5.50		5.53		5.48
Long Put Options	5,475,000		4.50		4.50		4.50
Short Put Options	5,475,000		4.00		4.00		4.00

In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks.

We had the following open derivative contracts for natural gas liquids at December 31, 2015:

NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Gal	Average		High		Low
2016
Price Swap Contracts	3,843,000	$	0.44	$	0.44	$	0.44

We had the following open financial basis swap contracts for natural gas at December 31, 2015:  

BASIS SWAP DERIVATIVE CONTRACTS

						Weighted
						Average Spread
Volume in MMBtu	Reference Price 1  (1)	Reference Price 2  (1)	Period			($ per MMBtu)
4,125,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Apr ’16	—	Dec ’16	$	0.27
1,350,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Jan ’17	—	Mar ’17		0.25

(1)    The spread in these trades limits the differential of the settlement quotation prices for Tex/OKL Panhandle Eastern Pipeline (PEPL) inside FERC (IFERC) over NYMEX Henry Hub.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

A summary of the changes in our asset retirement obligations is included in the table below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	62,872	$	56,023	$	48,593
Liabilities incurred		1,988		1,129		1,052
Liabilities assumed with acquired producing properties		—		3,002		5,480
Liabilities settled		(1,794)		(3,942)		(1,548)
Liabilities transferred in sales of properties		(3,149)		(1,886)		(606)
Revisions to estimates		(773)		6,348		919
Accretion expense		2,076		2,198		2,133
Balance, end of year		61,220		62,872		56,023
Less: Current portion		729		1,136		3,844
Long term portion	$	60,491	$	61,736	$	52,179

The total revisions included $1.5 million related to reductions to property, plant and equipment for the year ended December 31, 2015.  Total revisions included $2.9 million and $0.4 million related to additions to property, plant and equipment for the years ended December 31, 2014, and 2013, respectively.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

NOTE 8 — RELATED PARTY TRANSACTIONS

We have notes payable to our founder which bear interest at 10% with a balance of $25.7 million and $24.5 million at December 31, 2015 and 2014, respectively. See further information at Note 9.

Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received zero,  $516,500, and $17,500of capital distributions from us during the years ended December 31, 2015, 2014 and 2013, respectively.

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2015, 2014 and 2013 were approximately $133,000,  $150,000 and $175,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

David McClure, our Vice President, Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $275,000,  $450,000 and $390,000 for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

David Pepper, one of our Landmen, and the cousin of our Vice President, Land and Business Development, David Murrell, received total compensation of $146,000,  $260,000 and $125,000 for the years ended December 31, 2015, 2014 and 2013. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B partner, High Mesa, Inc. (“High Mesa”). We recorded $25.5 million in other receivable and $8.5 million in long term note receivable, while recording no gain or loss on the sale at December 31, 2014.  On January 2, 2015, the receivable of $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from Northwest Gas Processing, LLC (“NWGP”) to High Mesa Services, LLC, a subsidiary of High Mesa.  The Company believes the note to be fully collectible and accordingly has not recorded a reserve.  Interest income on the notes receivable from our affiliate amounted to $0.7 million during year ended December 31, 2015.  Such amounts have been added to the balance of the notes receivable.

On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million.  The receivables due from affiliate balance of $1.0 million as of December 31, 2015 includes the cost of repurchasing the land from NWGP.

During the year ended December 31, 2015, High Mesa, our Class B partner contributed $20 million to us.  For additional information, see Note 15- Partners’ Capital Deficit.

Alta Mesa is a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee.  For additional information on AEM, see Note 12.

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Long Term Debt

12 Months Ended

Dec. 31, 2015

Long Term Debt [Abstract]

Long Term Debt

NOTE 9 — LONG TERM DEBT

Long-term debt consists of the following:

	December 31,		December 31,
	2015		2014
	(in thousands)
Credit Facility	$	152,000	$	319,520
Senior Secured Term Loan		125,000		—
Senior Notes		448,598		448,088
Unamortized deferred financing costs		(7,823)		(6,466)
Total long-term debt	$	717,775	$	761,142
Notes payable to founder	$	25,748	$	24,540

Credit Facility. As of December 31, 2015, the Company had $152 million outstanding with $148 million of available borrowing capacity under the Sixth Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of banks.  On June 2, 2015, we entered into an Agreement and Amendment No. 11 (the “Eleventh Amendment”) to the credit facility.  The Eleventh Amendment, among other things, (i) redetermined and decreased the borrowing base from $375 million to $300 million, and (ii) extended the maturity date of the credit facility to October 13, 2017 from May 23, 2016.  The principal amount is payable at maturity.  On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the “Twelfth Amendment”) to amend the credit facility to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility.  As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million.  Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility.  The credit facility borrowing base is redetermined semi-annually on or about May 1 and November 1 of each year.  In November 2015, the lenders under the credit facility approved an increase in the borrowing base from $255 million to $300 million as part of the semi-annual redetermination.  The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 2.87% as of December 31, 2015 and 2.89% as of December 31, 2014.  The letters of credit outstanding as of December 31, 2015 and 2014 were $65,000 and $0.9 million, respectively.

The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expense of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.   

As of December 31, 2015, we were in compliance with all covenants.  The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility when it is next redetermined.

Subsequent to year end, on February 3, 2016, we entered into an Agreement and Amendment No. 13 to the credit facility (the “Thirteenth Amendment”). The Thirteenth Amendment, among other things: (a) permits us to enter into exchanges of outstanding senior notes for a third lien term loan, (b) permits us to draw the remaining borrowing base availability under the credit facility into a controlled account with such funds not being treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, (c) permits us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (d) requires that twice a month we transfer available cash in excess of $25 million to the controlled account, and (e) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.00 to 1.00 to 4.50 to 1.00.

Senior Secured Term Loan.  On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “Term Loan Facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million.  The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of additional term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The net proceeds of approximately $121 million from the Term Loan Facility, after payment of transaction-related fees and expenses, were used to pay down outstanding amounts under our existing credit facility.  The Term Loan Facility matures on April 15, 2018. Theprincipal amount is payable at maturity.

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  PV-9 is calculated using four year NYMEX strip pricing adjusted for differentials.  Obligations under the Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and affiliates and are secured by second priority liens on substantially all of our subsidiaries assets that serve as collateral under the credit facility.  As of December 31, 2015, we were in compliance with all covenants of the Term Loan Facility.

We have the option to prepay all or a portion of the Term Loan Facility at any time. The Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, subject to a limited right to reinvest proceeds in capital expenditures, or an initial public offering. Such prepayments are subject to a premium of between 3% declining to 1% prior to the maturity date, and, if made prior to the first anniversary of the closing date, are also subject to a “make whole” premium to ensure that the lenders receive the total amount of interest that would have been paid from the date of prepayment to such first anniversary.

Subsequent to year end, on February 3, 2016, we entered into the first amendment to the Term Loan Facility (the “First Amendment”). The First Amendment: (a) permits us to enter into exchanges of outstanding senior notes for third lien term loan, (b) allows us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (c) requires that twice a month we transfer available cash in excess of $25 million to a controlled account, with such funds in the controlled account to not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, and (d) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.50 to 1.00 to 5.00 to 1.00.

Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility and the Term Loan Facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.The balance is presented net of unamortized discount of $1.4 million and $1.9 million at December 31, 2015 and December 31, 2014, respectively.

The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016, respectively. 

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $25.7 million and $24.5 million at December 31, 2015 and December 31, 2014, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021.  Interest and principal are payable at maturity. Our founder may convert the notes into shares of our Class B partner’s, High Mesa, common stock upon certain conditions in the event of an initial public offering.

These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 15, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.

Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2015, 2014, and 2013. Such amounts have been added to the balance of the founder notes.

Deferred financing costs. As of December 31, 2015, the Company had $9.0 million of deferred financing costs related to the credit facility, Term Loan Facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $7.8 million related to the Term Loan Facility and senior notes are included in long-term debt on the consolidated balance sheet as of December 31, 2015 in accordance with ASU 2015-03, which we adopted in the fourth quarter of 2015 (see Note 2 — Summary of Significant Accounting Policies). Deferred financing costs of $1.2 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2015. Amortization of deferred financing costs recorded for the years ended December 31, 2015, 2014 and 2013 was $3.4 million, $2.9 million and $2.8 million, respectively. These costs are included in interest expense on the consolidated statement of operations.

Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized discount, at December 31, 2015 are as follows (in thousands):

Year ending December 31,
2016	$	—
2017		152,000
2018		575,000
2019		—
2020		—
Thereafter		25,748
	$	752,748

The credit facility, Term Loan Facility and senior notes also contain restrictive covenants that limit our ability to, among other things, incur or guarantee additional debt, make distributions (except distributions equal to the amount of income tax liabilities), repay subordinated debt prior to its maturity, grant additional liens on our assets, enter into transactions with our affiliates, enter into hedging transactions with non-lender hedge counterparties, repurchase equity securities, make certain investments or acquisitions of substantially all or a portion of another entity’s business assets, and merge with another entity of dispose of any material assets.

The credit facility, Term Loan Facility and senior notes contain customary events of default.  If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.

At December 31, 2015, we were in compliance with the covenants of our loan agreements.

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Accounts Payable And Accrued Liabilities

12 Months Ended

Dec. 31, 2015

Accounts Payable And Accrued Liabilities [Abstract]

Accounts Payable And Accrued Liabilities

NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

	December 31,		December 31,
	2015		2014
	(in thousands)
Capital expenditures	$	10,780	$	32,990
Revenues and royalties payable		5,082		7,302
Operating expenses/taxes		19,336		20,716
Interest		9,919		9,136
Compensation		5,434		10,586
Derivatives settlement payable		11,149		2,344
Other		1,201		261
Total accrued liabilities		62,901		83,335
Accounts payable		21,101		34,225
Accounts payable and accrued liabilities	$	84,002	$	117,560

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2015

Commitments And Contingencies [Abstract]

Commitments And Contingencies

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Contingencies

Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry.  Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource Company, LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive.  In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party.  On February 13, 2015, the case was dismissed by the U.S. District Judge. 

Environmental claims:  Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our consolidated financial statements at December 31, 2015.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  Management has established a liability for groundwater contamination in Florida of $1.3million at December 31, 2015 and $1.1 million at December 31, 2014, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.

Performance appreciation rights:  In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial designated value (“SIDV”).  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  Both the initial stipulated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors.  In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire. During 2015, we granted zero PARs and terminated 30,000 PARs with a SIDV of $40, resulting in 241,500 PARS issued at a weighted average value of $32.34.  Subsequent to year end, 360,000 PARs were issued with a SIDV of $40 and 3,500 PARs with a SIDV of $40 were terminated, resulting in 598,000 PARs issued at a weighted average value of $36.91.  We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan.  We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2015 and 2014.

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

Commitments

Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.Equipment leases are generally for four years or less. Rent expense, including office space and compressors, for the years ended December 31, 2015, 2014, and 2013 amounted to approximately $4.8 million, $5.7 million, and $5.3 million, respectively.

At December 31, 2015, future base rentals for non-cancelable operating leases are as follows (in thousands):

Year Ending December 31,
2016	$	4,130
2017		2,899
2018		1,574
2019		1,580
2020		1,593
Thereafter		2,827
	$	14,603

Additionally, at December 31, 2015, the Company had posted bonds in the aggregate amount of $24.4 million, primarily to cover future abandonment costs.

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Major Customers

12 Months Ended

Dec. 31, 2015

Major Customers [Abstract]

Major Customers

NOTE 12 — MAJOR CUSTOMERS

We sell our oil and natural gas primarily under a contract with AEM. We are a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee. Sales to AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015. During the second half of 2013 and throughout 2014 and 2015, we sold the majority of our production from operated fields to AEM. Production from non-operated fields, the most significant of which were our Eagleville oil field in South Texas and our Hilltop natural gas field in East Texas prior to their sale, was marketed on our behalf by the operators of those properties. Production from the Eagleville field was sold by Murphy Oil Corporation (“Murphy”), the operator of that property. Production from the Hilltop field was sold primarily by EnCana Oil & Gas (USA), Inc. (“EnCana”), the operator of a substantial portion of the wells in that field.

For the year ended December 31, 2015, revenues from AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities.  Based on revenues excluding hedging activities, no other major customer accounted for 10% or more of revenues.  For the year ended December 31, 2014, revenues from AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, one other major customer, Murphy accounted for 10% or more of revenues, with revenues excluding hedging activities of $61.2 million. For the year ended December 31, 2013, revenues from AEM were $61.3 million, or 16% of total revenue excluding hedging activities. Based on revenues excluding hedging activities,  three other major customers accounted for 10% or more of those revenues individually, with contributions of $119.3 million (Murphy), $53.9 million (Shell Trading (US) Company), and $42.0 million (Plains Marketing and Transportation, Inc.)  We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available. 

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401(k) Savings Plan

12 Months Ended

Dec. 31, 2015

Savings Plan [Abstract]

401(k) Savings Plan

NOTE 13 — 401(k) SAVINGS PLAN

Employees of Alta Mesa Services and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 50% of an employee’s salary deferral contribution up to a maximum of 8% of an employee’s salary. Matching contributions to the plan were approximately $710,000,  $683,000, and $585,000 for the years ended December 31, 2015, 2014, and 2013, respectively.

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Significant Risks And Uncertainties

12 Months Ended

Dec. 31, 2015

Significant Risks And Uncertainties [Abstract]

Significant Risks And Uncertainties

NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and 2015 and have declined dramatically since the second half of 2014.  Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves.  Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2016. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

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Partners' Capital (Deficit)

12 Months Ended

Dec. 31, 2015

Partners' Capital (Deficit) [Abstract]

Partners' Capital (Deficit)

NOTE 15 — PARTNERS’ CAPITAL (DEFICIT)

Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our sole Class B partner is High Mesa.  

On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our Board of Directors includes one member nominated by Highbridge and four members nominated by the Class A partners. 

Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the partnership agreement. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

Distribution and Income Allocation:In connection with the recapitalization on March 25, 2014, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until certain provisions are met.  After such provisions are met, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement.

The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility, Term Loan Facility, and our senior notes.

Net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.

For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. 

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Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

NOTE 16 — SUBSEQUENT EVENTS

Drillco Contract

On January 13, 2016, our wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”) with BCE-STACK Development LLC (the “BCE”), to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches.

Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate (each, a “Joint Well”), provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well.

On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million. The terms and conditions are the same as those of the first two tranches.

Drawdown under Credit Facility

On March 16, 2016, we borrowed $141.9million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility.  As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the Administrative Agent.  Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account.  These funds are intended to be used for general corporate purposes.

Following the funding of this borrowing, the aggregate principal amount of borrowings under the credit facility was $300.0million, including $6.1million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.

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Subsidiary Guarantors

12 Months Ended

Dec. 31, 2015

Subsidiary Guarantors [Abstract]

Subsidiary Guarantors

NOTE 17 — SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes, Term Loan Facility and our credit facility.

Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.

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Supplemental Quarterly Information

12 Months Ended

Dec. 31, 2015

Supplemental Quarterly Information [Abstract]

Supplemental Quarterly Information

NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited)

Results of operations by quarter for the year ended December 31, 2015 were:

	Quarter Ended
2015	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	60,542	$	71,755	$	61,344	$	48,325
Income (loss) from operations (1)(2)		(95,077)		(23,881)		110,069		(60,592)
Net income (loss)	$	(109,211)	$	(39,509)	$	93,079	$	(76,152)

(1) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015.

(2) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively.

Results of operations by quarter for the year ended December 31, 2014 were:

	Quarter Ended
2014	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	103,432	$	115,590	$	125,644	$	87,462
Income (loss) from operations (3)(4)		71,461		(25,186)		73,025		35,873
Net income (loss)	$	56,893	$	(38,812)	$	59,326	$	21,793

(3) Includes $73.1 million and $18.3 million gain on sale of asset during the quarters ended March 31, 2014 and September 30, 2014, respectively.

(4) Includes $18.3 million, and $8.7 million of impairment expense during the quarters ended June 30, 2014 and September 30, 2014, respectively.

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Supplemental Oil And Natural Gas Disclosures

12 Months Ended

Dec. 31, 2015

Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]

Supplemental Oil And Natural Gas Disclosures (Unaudited)

NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)

The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. 

Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2015, 2014, and 2013, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

	Oil	Gas	NGL's	BOE
	(MBbls)	(MMcf)	(MBbls)	(MBbls)
Total Proved Reserves:
Balance at December 31, 2012	20,620	152,489	5,695	51,731
Production	(2,897)	(16,664)	(398)	(6,072)
Purchases in place	1,462	1,265	—	1,673
Discoveries and extensions	14,541	29,012	1,969	21,345
Sales of reserves in place	(13)	(10,912)	—	(1,832)
Revisions of previous quantity estimates and other	(1,196)	(22,925)	(1,531)	(6,549)
Balance at December 31, 2013	32,517	132,265	5,735	60,296
Production	(3,770)	(14,449)	(537)	(6,715)
Purchases in place	610	327	—	665
Discoveries and extensions	13,281	28,822	4,119	22,204
Sales of reserves in place	(6,298)	(35,857)	(949)	(13,223)
Revisions of previous quantity estimates and other	(4,996)	(7,960)	20	(6,304)
Balance at December 31, 2014	31,344	103,148	8,388	56,923
Production	(4,203)	(11,900)	(678)	(6,865)
Discoveries and extensions	12,981	58,129	7,763	30,432
Sales of reserves in place	(6,544)	(8,250)	(748)	(8,667)
Revisions of previous quantity estimates and other	564	14,296	3,712	6,660
Balance at December 31, 2015	34,142	155,423	18,437	78,483
Proved Developed Reserves:
Balance at December 31, 2013	16,335	92,640	3,138	34,913
Balance at December 31, 2014	15,182	63,334	4,028	29,765
Balance at December 31, 2015	14,942	71,752	6,958	33,859
Proved Undeveloped Reserves:
Balance at December 31, 2013	16,182	39,625	2,597	25,383
Balance at December 31, 2014	16,162	39,814	4,360	27,158
Balance at December 31, 2015	19,200	83,671	11,479	44,624

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

	December 31,
	2015		2014
	(in thousands)
Capitalized costs:
Proved properties	$	1,345,482	$	1,417,785
Unproved properties		127,551		84,620
Total		1,473,033		1,502,405
Accumulated depreciation, depletion, amortization and impairment		(947,091)		(816,229)
Net capitalized costs	$	525,942	$	686,176

Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Costs incurred during the year:
Property acquisition costs
Unproved (1)	$	74,475	$	33,787	$	34,884
Proved (2)		2,899		7,462		35,954
Exploration		34,275		59,201		55,300
Development (3)		146,299		341,594		242,912
	$	257,948	$	442,044	$	369,050

(1) Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million.

(2) Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. 

(3) Includes asset retirement additions (revisions) of ($0.3)million, $4.5 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Standardized Measure of Discounted Future Net Cash Flows

The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Future cash inflows as of December 31, 2015 and 2014 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2015, 2014, and 2013:

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Future cash flows	$	2,395,128	$	3,737,412	$	3,959,938
Future production costs		(860,600)		(991,149)		(1,146,123)
Future development costs		(403,953)		(450,659)		(474,191)
Future taxes on income		—		—		—
Future net cash flows		1,130,575		2,295,604		2,339,624
Discount to present value at 10 percent per annum		(500,979)		(877,558)		(933,350)
Standardized measure of discounted future net cash flows	$	629,596	$	1,418,046	$	1,406,274
Base price for crude oil, per Bbl, in the above computation was:	$	50.28	$	94.99	$	96.78
Base price for natural gas, per Mcf, in the above computation was:	$	2.58	$	4.35	$	3.67

No consideration was given to the Company’s hedged transactions.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in standardized measure of discounted future net cash flows:

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Balance at beginning of year	$	1,418,046	$	1,406,274	$	914,421
Sales of oil and natural gas, net of production costs		(147,906)		(320,130)		(263,952)
Changes in sales and transfer prices, net of production costs		(823,073)		(153,770)		69,609
Revisions of previous quantity estimates		53,101		(477,377)		(150,634)
Purchases of reserves-in-place		—		21,633		93,877
Sales of reserves-in-place		(244,251)		(107,414)		(11,193)
Current year discoveries and extensions		260,078		701,820		621,832
Changes in estimated future development costs		4,376		2,591		11,623
Development costs incurred during the year		42,420		161,357		75,973
Accretion of discount		141,805		140,627		91,442
Net change in income taxes		—		—		—
Change in production rate (timing) and other		(75,000)		42,435		(46,724)
Net change		(788,450)		11,772		491,853
Balance at end of year	$	629,596	$	1,418,046	$	1,406,274

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Principles Of Consolidation And Reporting

Principles of Consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

Use Of Estimates

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 reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Reclassifications

Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ deficit.

In the fourth quarter of 2015, the Company adopted Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs.  In accordance with the new guidance, deferred financing costs related to the Company’s senior unsecured notes and Term Loan Facility (as defined in Note 9), which had been included in deferred financing costs, net under other assets on the consolidated balance sheets prior to the adoption of ASU 2015-03, are now included in long-term debt on the consolidated balance sheets, resulting in decreases in both deferred financing costs, net and long-term debt of $7.8 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual period presented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the consolidated balance sheet as of December 31, 2014 included a deduction for deferred financing costs of $6.5 million in long-term debt, which had previously been presented in deferred financing costs, net under other assets. Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

Cash And Cash Equivalents

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash

Restricted Cash.The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2015, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute.  As of December 31, 2014, the Company had $24.6 million of proceeds remaining in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code from the sale of our Hilltop field Deep Bossier properties. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions, and in March 2015, the remaining $23.7 million of restricted cash was returned to us to be used for general corporate purposes and, as such, was classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014.  The Company planned to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures.

Accounts Receivable

Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized.  Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $9.8 million and $10.3 million at December 31, 2015 and 2014, respectively.  Trade receivables from the sale of oil and natural gas were $17.9 million and $35.1 million at December 31, 2015 and 2014, respectively.  See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC (“AEM”).  Accounts receivable from AEM were $12.6 million and $16.6 million as of December 31, 2015 and 2014, respectively.

Allowance For Doubtful Accounts

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.

Deferred Financing Costs

Deferred Financing Costs.The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

Property And Equipment

Property and Equipment. Oil and natural 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 leases are recorded as unproved properties 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. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet 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. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. 

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas 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.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or 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 at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Our evaluation of the Company’s proved properties resulted in impairment expense of $172.0 million,$72.9 million and $135.2 million for the years ended December 31, 2015, 2014, and 2013, respectively, primarily due to lower forecasted commodity prices.

Unproved properties 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 properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2015, 2014 and 2013, impairment expense of unproved properties was $4.8 million, $2.0 million, and $8.0 million, respectively.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2015, 2014, and 2013, respectively, the Company did not record any impairment expense related to other long-lived assets.

Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. 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 lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

DD&A expense for the years ended December 31, 2015, 2014, and 2013 related to oil and natural gas properties was $140.9 million, $139.0 million, and $115.5 million, respectively.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2015, 2014, and 2013 was $3.0 million, $2.8 million, and $3.1 million respectively.

Investment

Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.

Asset Retirement Obligations

Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.  Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.

Income Taxes

Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “ Provision for state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

We have considered our exposure under the standard at both the federal and state tax levels.  We have not recorded any liabilities for uncertain tax positions as of December 31, 2015 and 2014. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2015,  2014, or 2013.  

The Company’s tax returns for the years ended December 31, 2012 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Revenue Recognition

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed.

Fair Value Of Financial Instruments

Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk.  The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.  We have estimated the fair value of our $450 million senior notes payable at $162 million on December 31, 2015. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 5 – Fair value disclosures and Note 9 - Long-term debt.

Acquisitions

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”).  ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach. 

In September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.

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Derivative Financial Instruments (Policy)

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments [Line Items]

Derivatives And Hedging

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.

Commodity Contract [Member]

Derivative Financial Instruments [Line Items]

Derivatives, Use of Derivatives

We account for our derivative contracts under the provisions of ASC 815, "Derivatives and Hedging." We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly.

Interest Rate Contracts [Member]

Derivative Financial Instruments [Line Items]

Derivatives, Use of Derivatives

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

Netting Presentation for Derivatives Policy [Member]

Derivative Financial Instruments [Line Items]

Derivatives And Hedging

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets.  Likewise, derivative (liabilities) could be presented in an asset account.

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Significant Acquisition And Divestitures (Tables)

12 Months Ended

Dec. 31, 2015

Significant Acquisition and Divestitures [Abstract]

Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices

	October 1,
	2013
	(in thousands)
Summary of Consideration
Cash	$	41,841
Fair value of asset retirement obligations assumed		5,311
Total	$	47,152
Summary of Purchase Price Allocation
Proved oil and natural gas properties	$	30,279
Unproved oil and natural gas properties		16,873
Total	$	47,152

Summary Of Pro Forma Information

	Total		Income
	Revenue		(Loss)
	(in thousands)
Actual results of Stone included in our statement of operations for the period October 1, 2013
through December 31, 2013	$	10,509	$	8,575
Pro forma results for the combined entity for the year ended December 31, 2013	$	376,063	$	(146,866)

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Property And Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property And Equipment [Abstract]

Property And Equipment

	December 31,		December 31,
	2015		2014
	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	127,551	$	84,620
Accumulated impairment		(2,684)		(3,749)
Unproved properties, net		124,867		80,871
Proved oil and natural gas properties		1,345,482		1,417,785
Accumulated depreciation, depletion, amortization and impairment		(944,407)		(812,480)
Proved oil and natural gas properties, net		401,075		605,305
TOTAL OIL AND NATURAL GAS PROPERTIES, net		525,942		686,176
LAND		3,868		2,820
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		18,794		17,302
Accumulated depreciation		(11,565)		(8,617)
OTHER PROPERTY AND EQUIPMENT, net		7,229		8,685
TOTAL PROPERTY AND EQUIPMENT, net	$	537,039	$	697,681

Capitalized Exploratory Well Costs Roll Forward Table

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	13,301	$	20,317	$	3,863
Additions to capitalized well costs pending determination of proved reserves		4,364		15,870		21,387
Reclassifications to proved properties		(8,583)		(6,593)		(4,933)
Capitalized exploratory well costs charged to expense		(3,076)		(16,293)		—
Balance, end of year	$	6,006	$	13,301	$	20,317

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Fair Value Disclosures (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis

	Level 1		Level 2		Level 3		Total
		(in thousands)
At December 31, 2015:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	166,106		—	$	166,106
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	61,840		—	$	61,840
At December 31, 2014:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	140,652		—	$	140,652
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	53,578		—	$	53,578

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative [Line Items]

Fair Values Of Derivative Contracts

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2015	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	86,000	$	(23,369)	$	62,631
Derivative financial instruments, long-term assets		80,106		(38,471)		41,635
Total	$	166,106	$	(61,840)	$	104,266

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2015	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	23,369	$	(23,369)	$	—
Derivative financial instruments, long-term liabilities		38,471		(38,471)		—
Total	$	61,840	$	(61,840)	$	—

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2014	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	91,341	$	(31,538)	$	59,803
Derivative financial instruments, long-term assets		55,325		(28,054)		27,271
Total	$	146,666	$	(59,592)	$	87,074

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2014	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	31,538	$	(31,538)	$	—
Derivative financial instruments, long-term liabilities		28,054		(28,054)		—
Total	$	59,592	$	(59,592)	$	—

Effect Of Derivative Instruments In The Consolidated Statements Of Operations

Derivatives not
designated as hedging	Location of	Year Ended December 31,
instruments under ASC 815	Gain (Loss)	2015		2014		2013
		(in thousands)
Oil commodity contracts	Gain (loss) on derivative contracts	$	113,295	$	82,510	$	(17,715)
Natural gas commodity contracts	Gain on derivative contracts		10,712		14,049		565
Natural gas liquids commodity contracts	Gain on derivative contracts		134		—		—
Total gains (losses) from
derivatives not designated as hedges		$	124,141	$	96,559	$	(17,150)

Oil Derivative Contracts [Member]

Derivative [Line Items]

Open Derivative Contracts

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2016
Price Swap Contracts	2,532,300	$	64.16	$	94.92	$	53.00
Collar Contracts
Short Call Options	739,100		99.69		130.00		75.00
Long Put Options	603,800		63.71		95.00		40.55
Short Put Options	420,800		72.81		75.00		65.00
2017
Collar Contracts
Short Call Options	1,960,150		85.02		113.83		62.50
Long Put Options	1,412,650		72.27		90.00		60.00
Short Put Options	1,412,650		54.63		70.00		45.00
2018
Collar Contracts
Short Call Options	1,183,000		80.51		104.65		72.00
Long Put Options	1,183,000		67.05		80.00		62.50
Short Put Options	1,183,000		48.90		60.00		45.00
2019
Collar Contracts
Short Call Options	821,250		75.17		75.70		74.50
Long Put Options	821,250		62.50		62.50		62.50
Short Put Options	821,250		45.00		45.00		45.00

Natural Gas Derivative Contract [Member]

Derivative [Line Items]

Open Derivative Contracts

	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2016
Price Swap Contracts	7,320,000	$	3.05	$	3.17	$	2.95
Collar Contracts
Short Call Options	1,510,000		2.40		2.40		2.40
Long Put Options	1,510,000		2.25		2.25		2.25
2017
Collar Contracts
Short Call Options	6,570,000		5.00		5.00		4.98
Long Put Options	6,570,000		4.50		4.50		4.50
Short Put Options	6,570,000		4.00		4.00		4.00
2018
Collar Contracts
Short Call Options	5,475,000		5.50		5.53		5.48
Long Put Options	5,475,000		4.50		4.50		4.50
Short Put Options	5,475,000		4.00		4.00		4.00

Natural Gas Liquids Derivative Contracts [Member]

Derivative [Line Items]

Open Derivative Contracts

	Volume	Weighted		Range
Period and Type of Contract	in Gal	Average		High		Low
2016
Price Swap Contracts	3,843,000	$	0.44	$	0.44	$	0.44

Basis Swap Derivative Contract [Member]

Derivative [Line Items]

Open Financial Basis Swap Contracts

						Weighted
						Average Spread
Volume in MMBtu	Reference Price 1  (1)	Reference Price 2  (1)	Period			($ per MMBtu)
4,125,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Apr ’16	—	Dec ’16	$	0.27
1,350,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Jan ’17	—	Mar ’17		0.25

(1)    The spread in these trades limits the differential of the settlement quotation prices for Tex/OKL Panhandle Eastern Pipeline (PEPL) inside FERC (IFERC) over NYMEX Henry Hub.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligations [Abstract]

Summary Of Changes In Asset Retirement Obligations

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance, beginning of year	$	62,872	$	56,023	$	48,593
Liabilities incurred		1,988		1,129		1,052
Liabilities assumed with acquired producing properties		—		3,002		5,480
Liabilities settled		(1,794)		(3,942)		(1,548)
Liabilities transferred in sales of properties		(3,149)		(1,886)		(606)
Revisions to estimates		(773)		6,348		919
Accretion expense		2,076		2,198		2,133
Balance, end of year		61,220		62,872		56,023
Less: Current portion		729		1,136		3,844
Long term portion	$	60,491	$	61,736	$	52,179

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Long Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Long Term Debt [Abstract]

Long-Term Debt And Notes Payable To Founder

	December 31,		December 31,
	2015		2014
	(in thousands)
Credit Facility	$	152,000	$	319,520
Senior Secured Term Loan		125,000		—
Senior Notes		448,598		448,088
Unamortized deferred financing costs		(7,823)		(6,466)
Total long-term debt	$	717,775	$	761,142
Notes payable to founder	$	25,748	$	24,540

Summary Of Future Maturities Of Long-Term Debt

Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized discount, at December 31, 2015 are as follows (in thousands):

Year ending December 31,
2016	$	—
2017		152,000
2018		575,000
2019		—
2020		—
Thereafter		25,748
	$	752,748

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Accounts Payable And Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Accounts Payable And Accrued Liabilities [Abstract]

Detail Of Accounts Payable And Accrued Liabilities

	December 31,		December 31,
	2015		2014
	(in thousands)
Capital expenditures	$	10,780	$	32,990
Revenues and royalties payable		5,082		7,302
Operating expenses/taxes		19,336		20,716
Interest		9,919		9,136
Compensation		5,434		10,586
Derivatives settlement payable		11,149		2,344
Other		1,201		261
Total accrued liabilities		62,901		83,335
Accounts payable		21,101		34,225
Accounts payable and accrued liabilities	$	84,002	$	117,560

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments And Contingencies [Abstract]

Future Base Rentals For Non-Cancelable Leases

At December 31, 2015, future base rentals for non-cancelable operating leases are as follows (in thousands):

Year Ending December 31,
2016	$	4,130
2017		2,899
2018		1,574
2019		1,580
2020		1,593
Thereafter		2,827
	$	14,603

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Supplemental Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Quarterly Information [Abstract]

Summary Of Quarterly Results Of Operations

Results of operations by quarter for the year ended December 31, 2015 were:

	Quarter Ended
2015	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	60,542	$	71,755	$	61,344	$	48,325
Income (loss) from operations (1)(2)		(95,077)		(23,881)		110,069		(60,592)
Net income (loss)	$	(109,211)	$	(39,509)	$	93,079	$	(76,152)

(1) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015.

(2) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively.

Results of operations by quarter for the year ended December 31, 2014 were:

	Quarter Ended
2014	March 31		June 30		Sept 30		Dec 31
		(in thousands)
Revenues	$	103,432	$	115,590	$	125,644	$	87,462
Income (loss) from operations (3)(4)		71,461		(25,186)		73,025		35,873
Net income (loss)	$	56,893	$	(38,812)	$	59,326	$	21,793

(3) Includes $73.1 million and $18.3 million gain on sale of asset during the quarters ended March 31, 2014 and September 30, 2014, respectively.

(4) Includes $18.3 million, and $8.7 million of impairment expense during the quarters ended June 30, 2014 and September 30, 2014, respectively.

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Supplemental Oil And Natural Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]

Estimated Quantities Of Proved Reserves

	Oil	Gas	NGL's	BOE
	(MBbls)	(MMcf)	(MBbls)	(MBbls)
Total Proved Reserves:
Balance at December 31, 2012	20,620	152,489	5,695	51,731
Production	(2,897)	(16,664)	(398)	(6,072)
Purchases in place	1,462	1,265	—	1,673
Discoveries and extensions	14,541	29,012	1,969	21,345
Sales of reserves in place	(13)	(10,912)	—	(1,832)
Revisions of previous quantity estimates and other	(1,196)	(22,925)	(1,531)	(6,549)
Balance at December 31, 2013	32,517	132,265	5,735	60,296
Production	(3,770)	(14,449)	(537)	(6,715)
Purchases in place	610	327	—	665
Discoveries and extensions	13,281	28,822	4,119	22,204
Sales of reserves in place	(6,298)	(35,857)	(949)	(13,223)
Revisions of previous quantity estimates and other	(4,996)	(7,960)	20	(6,304)
Balance at December 31, 2014	31,344	103,148	8,388	56,923
Production	(4,203)	(11,900)	(678)	(6,865)
Discoveries and extensions	12,981	58,129	7,763	30,432
Sales of reserves in place	(6,544)	(8,250)	(748)	(8,667)
Revisions of previous quantity estimates and other	564	14,296	3,712	6,660
Balance at December 31, 2015	34,142	155,423	18,437	78,483
Proved Developed Reserves:
Balance at December 31, 2013	16,335	92,640	3,138	34,913
Balance at December 31, 2014	15,182	63,334	4,028	29,765
Balance at December 31, 2015	14,942	71,752	6,958	33,859
Proved Undeveloped Reserves:
Balance at December 31, 2013	16,182	39,625	2,597	25,383
Balance at December 31, 2014	16,162	39,814	4,360	27,158
Balance at December 31, 2015	19,200	83,671	11,479	44,624

Capitalized Costs Relating To Oil And Natural Gas Producing Activities

	December 31,
	2015		2014
	(in thousands)
Capitalized costs:
Proved properties	$	1,345,482	$	1,417,785
Unproved properties		127,551		84,620
Total		1,473,033		1,502,405
Accumulated depreciation, depletion, amortization and impairment		(947,091)		(816,229)
Net capitalized costs	$	525,942	$	686,176

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Costs incurred during the year:
Property acquisition costs
Unproved (1)	$	74,475	$	33,787	$	34,884
Proved (2)		2,899		7,462		35,954
Exploration		34,275		59,201		55,300
Development (3)		146,299		341,594		242,912
	$	257,948	$	442,044	$	369,050

(1) Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million.

(2) Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. 

(3) Includes asset retirement additions (revisions) of ($0.3)million, $4.5 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Components Of The Standardized Measure Of Discounted Future Net Cash Flows

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Future cash flows	$	2,395,128	$	3,737,412	$	3,959,938
Future production costs		(860,600)		(991,149)		(1,146,123)
Future development costs		(403,953)		(450,659)		(474,191)
Future taxes on income		—		—		—
Future net cash flows		1,130,575		2,295,604		2,339,624
Discount to present value at 10 percent per annum		(500,979)		(877,558)		(933,350)
Standardized measure of discounted future net cash flows	$	629,596	$	1,418,046	$	1,406,274
Base price for crude oil, per Bbl, in the above computation was:	$	50.28	$	94.99	$	96.78
Base price for natural gas, per Mcf, in the above computation was:	$	2.58	$	4.35	$	3.67

Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows

	Year Ended December 31,
	2015		2014		2013
		(in thousands)
Balance at beginning of year	$	1,418,046	$	1,406,274	$	914,421
Sales of oil and natural gas, net of production costs		(147,906)		(320,130)		(263,952)
Changes in sales and transfer prices, net of production costs		(823,073)		(153,770)		69,609
Revisions of previous quantity estimates		53,101		(477,377)		(150,634)
Purchases of reserves-in-place		—		21,633		93,877
Sales of reserves-in-place		(244,251)		(107,414)		(11,193)
Current year discoveries and extensions		260,078		701,820		621,832
Changes in estimated future development costs		4,376		2,591		11,623
Development costs incurred during the year		42,420		161,357		75,973
Accretion of discount		141,805		140,627		91,442
Net change in income taxes		—		—		—
Change in production rate (timing) and other		(75,000)		42,435		(46,724)
Net change		(788,450)		11,772		491,853
Balance at end of year	$	629,596	$	1,418,046	$	1,406,274

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Summary Of Significant Accounting Policies (Details) - USD ($)	1 Months Ended	12 Months Ended
	Mar. 25, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
FDIC insured maximum amount		$ 250,000
Proceeds from sale of property		141,404,000	$ 177,476,000	$ 26,668,000
Amount of restricted cash refunded from investment	$ 23,700,000
Long-term restricted cash			900,000
Receivables from joint interest owners		9,800,000	10,300,000
Receivables from oil, natural gas, and natural gas liquids sales		17,900,000	35,100,000
Impairment expense of proved properties		172,000,000	72,900,000	135,200,000
Impairment expense of unproved properties		4,800,000	2,000,000	8,000,000
Depreciation depletion and amortization related to oil and gas properties		140,900,000	139,000,000	115,500,000
Depreciation expense for other property and equipment		$ 3,000,000	2,800,000	3,100,000
Ownership interest in a drilling company		10.17%
Liability for uncertain tax positions		$ 0	0
Income tax penalties and interest		0	0	$ 0
Face value of senior notes issued		450,000,000
Fair value of senior notes payable		162,000,000
Deferred financing cost, net reclassed to LT Debt		7,800,000	6,500,000
ARM Energy Management, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable		$ 12,600,000	16,600,000
Hilltop Field Deep Bossier Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Proceeds from sale of property			$ 24,600,000
Drilling Rig [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment		15 years
Minimum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment		3 years
Maximum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment		7 years

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Significant Acquisition and Divestitures (Narrative) (Details) bbl in Millions, MMBbls in Millions					3 Months Ended			12 Months Ended
	Jul. 06, 2015 USD ($) a	Sep. 19, 2014 USD ($) MMcf	Oct. 01, 2013 USD ($)	Jul. 01, 2013 MMcf bbl	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) bbl	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jul. 01, 2015 MMBbls
Business Acquisition [Line Items]
Payment towards acquisition of all working interests										$ 42,000,000
Gain (loss) on sale of assets					$ 66,400,000	$ 18,300,000	$ 73,100,000	$ 67,781,000	$ 87,520,000	(2,715,000)
Other receivables								18,526,000	8,238,000
Drilling Rig [Member]
Business Acquisition [Line Items]
Sale of drilling rig, cash purchase price									7,000,000
Gain (loss) on sale of assets									(1,200,000)
Alta Mesa Eagle, LLC Divestiture [Member]
Business Acquisition [Line Items]
Initial cash purchase price for properties sold								118,000,000
Cash purchase price								125,000,000
Additional contingent payment								7,000,000
Adjusted cash purchase price, net of costs of transaction								4,000,000
Estimated proved reserves | MMBbls											7.8
Gain on sale of oil and gas properties								67,600,000	72,500,000
Operating income from sold oil and gas properties								68,900,000	118,500,000
Other receivables								$ 122,000,000
Oklahoma [Member]
Business Acquisition [Line Items]
Net acres | a	19,000
Cash consideration for Undeveloped Leasehold	$ 46,200,000
Eagleville Divestiture [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties								Mar. 25, 2014
Percentage of original working interest net profits interest in wells is retained on, 2014								50.00%
Percentage of original working interest net profits interest in wells is retained on, 2015								30.00%
Percentage of original working interest net profits interest in wells is retained on, 2016								15.00%
Percentage of original working interest net profits interest in wells is retained on, 2017								0.00%
Percentage of undivided interest in mineral leases and interests included in sale								30.00%
Percentage of working interest in all wells in progress on December 31, 2013 or drilled after January 1, 2014 included in sale								30.00%
Initial cash purchase price for properties sold								$ 173,000,000
Cash purchase price								$ 171,000,000
Gain on sale of oil and gas properties									72,500,000
Operating income from sold oil and gas properties							$ 11,100,000			47,000,000
Eagleville Divestiture [Member] | Barrels of Oil Equivalent [Member]
Business Acquisition [Line Items]
Estimated proved reserves | bbl								7.5
Hilltop Divestiture 2014 [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties								Sep. 19, 2014
Cash purchase price		$ 41,600,000						$ 38,900,000
Gain on sale of oil and gas properties								$ 15,900,000
Operating income from sold oil and gas properties									$ 7,700,000
Hilltop Divestiture 2014 [Member] | Natural Gas in MMcf [Member]
Business Acquisition [Line Items]
Estimated proved reserves | MMcf		29,800
Hilltop Divestiture 2013 [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties								Oct. 02, 2013
Cash purchase price								$ 19,000,000
Gain on sale of oil and gas properties								$ 0
Operating income from sold oil and gas properties										$ 6,900,000
Hilltop Divestiture 2013 [Member] | Natural Gas in MMcf [Member]
Business Acquisition [Line Items]
Estimated proved reserves | MMcf				11,200
Stone [Member]
Business Acquisition [Line Items]
Acquisition effective date								Oct. 01, 2013
Payment towards acquisition of all working interests			$ 41,841,000
Total estimated net proved reserves acquired | bbl				1.8
Acquisition effective date								Jul. 01, 2013

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Significant Acquisition And Divestitures (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Details) - USD ($) $ in Thousands		12 Months Ended
	Oct. 01, 2013	Dec. 31, 2013
Business Acquisition [Line Items]
Cash		$ 42,000
Stone [Member]
Business Acquisition [Line Items]
Cash	$ 41,841
Fair value of asset retirement obligations assumed	5,311
Total	47,152
Proved oil and natural gas properties	30,279
Unproved oil and natural gas properties	16,873
Total	$ 47,152

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Significant Acquisition And Divestitures (Summary Of Pro Forma Information) (Details) - Stone [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($)
Scenario, Actual [Member]
Business Acquisition [Line Items]
Actual revenue since acquisition	$ 10,509
Actual income (loss) since acquisition	8,575
Pro Forma [Member]
Business Acquisition [Line Items]
Pro Forma Revenue	376,063
Pro Forma Income (Loss)	$ (146,866)

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Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property And Equipment [Abstract]
Unproved properties	$ 127,551	$ 84,620
Accumulated impairment	(2,684)	(3,749)
Unproved properties, net	124,867	80,871
Proved oil and natural gas properties	1,345,482	1,417,785
Accumulated depreciation, depletion, amortization and impairment	(944,407)	(812,480)
Proved oil and natural gas properties, net	401,075	605,305
TOTAL OIL AND NATURAL GAS PROPERTIES, net	525,942	686,176
LAND	3,868	2,820
Office furniture and equipment, vehicles	18,794	17,302
Accumulated depreciation	(11,565)	(8,617)
OTHER PROPERTY AND EQUIPMENT, net	7,229	8,685
Total property and equipment, net	$ 537,039	$ 697,681

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Property And Equipment (Capitalized Exploratory Well Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves
Capitalized Exploratory Well Costs, Beginning Balance	$ 13,301	$ 20,317	$ 3,863
Additions to capitalized well costs pending determination of proved reserves	4,364	15,870	21,387
Reclassifications to proved based on determination of proved reserves	(8,583)	(6,593)	(4,933)
Capitalized Exploratory Well Costs, Ending Balance	$ 6,006	13,301	$ 20,317
Number of wells included in ending balance in deferred capitalized exploratory well costs | item	6
Number of prospects | item	2
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 3,000	$ 2,200

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Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Line Items]
Carrying value of oil and gas properties						$ 499,600	$ 148,400	$ 237,200
Written down fair value of oil and gas properties						322,800	73,500	94,000
Impairment charges to oil and gas properties	$ 90,500	$ 8,900	$ 73,100	$ 8,700	$ 18,300	176,774	74,927	143,166
Asset retirement obligation measured at fair value						$ 2,000	$ 4,100
Stone [Member]
Fair Value Disclosures [Line Items]
Fair value of oil and gas properties acquired								$ 47,200

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Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Financial Assets:
Derivative contracts for oil and natural gas, gross	$ 166,106	$ 140,652
Financial Liabilities:
Derivative contracts for oil and natural gas, gross	$ 61,840	$ 53,578
Level 1 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross
Financial Liabilities:
Derivative contracts for oil and natural gas, gross
Level 2 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross	$ 166,106	$ 140,652
Financial Liabilities:
Derivative contracts for oil and natural gas, gross	$ 61,840	$ 53,578
Level 3 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross
Financial Liabilities:
Derivative contracts for oil and natural gas, gross

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Derivative Financial Instruments (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Financial Instruments [Abstract]
Derivative Asset, Setoff Rights, Description	Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.
Derivative receivables	$ 17,500	$ 8,000

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Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	$ 166,106	$ 146,666
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	(61,840)	(59,592)
Derivative Assets, Current	62,631	59,803
Derivative Assets, Noncurrent	41,635	27,271
Derivative assets, net, total	104,266	87,074
Derivative liabilities, Gross Fair Value of Liabilities	61,840	59,592
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	(61,840)	(59,592)
Derivative Assets Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	86,000	91,341
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	(23,369)	(31,538)
Derivative Assets, Current	62,631	59,803
Derivative Asset Non-Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	80,106	55,325
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	(38,471)	(28,054)
Derivative Assets, Noncurrent	41,635	27,271
Derivative Liabilities Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	23,369	31,538
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	(23,369)	(31,538)
Derivative Liabilities Non Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	38,471	28,054
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	$ (38,471)	$ (28,054)
Derivative Liabilities, Noncurrent

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Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	$ 124,141	$ 96,559	$ (17,150)
Oil Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	113,295	82,510	(17,715)
Natural Gas Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	10,712	14,049	565
Natural Gas Liquids Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	134
Not Designated As Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	$ 124,141	$ 96,559	$ (17,150)

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Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil Derivative Contracts [Member]	12 Months Ended
	Dec. 31, 2015 $ / bbl bbl
Price Swap Contracts [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,532,300
Weighted Average Swap Price	64.16
Price Swap Contracts [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	94.92
Price Swap Contracts [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	53.00
Short Call Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	739,100
Weighted Average Option Price	99.69
Short Call Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	130.00
Short Call Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	75.00
Short Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,960,150
Weighted Average Option Price	85.02
Short Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	113.83
Short Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.50
Short Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,183,000
Weighted Average Option Price	80.51
Short Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	104.65
Short Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	72.00
Short Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	821,250
Weighted Average Option Price	75.17
Short Call Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	75.70
Short Call Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	74.50
Long Put Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	603,800
Weighted Average Option Price	63.71
Long Put Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	95.00
Long Put Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	40.55
Long Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,412,650
Weighted Average Option Price	72.27
Long Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	90.00
Long Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60.00
Long Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,183,000
Weighted Average Option Price	67.05
Long Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	80.00
Long Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.50
Long Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	821,250
Weighted Average Option Price	62.50
Long Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	62.50
Long Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.50
Short Put Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	420,800
Weighted Average Option Price	72.81
Short Put Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	75.00
Short Put Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	65.00
Short Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,412,650
Weighted Average Option Price	54.63
Short Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	70.00
Short Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	45.00
Short Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,183,000
Weighted Average Option Price	48.90
Short Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	60.00
Short Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	45.00
Short Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	821,250
Weighted Average Option Price	45.00
Short Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	45.00
Short Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	45.00

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Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2015 MMBTU $ / MMBTU
2016 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,320,000
Weighted Average Swap Price	3.05
2016 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	3.17
2016 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	2.95
2016 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,510,000
Weighted Average Option Price	2.40
2016 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.40
2016 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.40
2016 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,510,000
Weighted Average Option Price	2.25
2016 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.25
2016 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.25
2017 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,570,000
Weighted Average Option Price	5.00
2017 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.00
2017 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.98
2017 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,570,000
Weighted Average Option Price	4.50
2017 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.50
2017 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.50
2017 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,570,000
Weighted Average Option Price	4.00
2017 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.00
2017 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.00
2018 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,475,000
Weighted Average Option Price	5.50
2018 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.53
2018 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	5.48
2018 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,475,000
Weighted Average Option Price	4.50
2018 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.50
2018 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.50
2018 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,475,000
Weighted Average Option Price	4.00
2018 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.00
2018 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.00

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Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Details) - 2016 [Member] - Natural Gas Liquids Derivative Contracts [Member] - Price Swap Contracts [Member]	12 Months Ended
	Dec. 31, 2015 $ / gal gal
Derivative [Line Items]
Volume in Gal | gal	3,843,000
Weighted Average Swap Price	0.44
Minimum [Member]
Derivative [Line Items]
Swap Price	0.44
Maximum [Member]
Derivative [Line Items]
Swap Price	0.44

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Derivative Financial Instruments (Gas Basis Swaps) (Details) - Financial Basis Swap Contracts For Gas [Member]	12 Months Ended
	Dec. 31, 2015 MMBTU $ / MMBTU
2016 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	4,125,000
First remaining period of term of derivative contract	Apr. 01, 2016
Last remaining period of term of derivative contract	Dec. 31, 2016
Weighted average spread | $ / MMBTU	0.27
2017 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,350,000
First remaining period of term of derivative contract	Jan. 01, 2017
Last remaining period of term of derivative contract	Mar. 31, 2017
Weighted average spread | $ / MMBTU	0.25

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations [Abstract]
Balance, beginning of year	$ 62,872	$ 56,023	$ 48,593
Liabilities incurred	1,988	1,129	1,052
Liabilities assumed with acquired producing properties		3,002	5,480
Liabilities settled	(1,794)	(3,942)	(1,548)
Liabilities transferred in sales of properties	(3,149)	(1,886)	(606)
Revisions to estimates	(773)	6,348	919
Accretion expense	2,076	2,198	2,133
Balance, end of period	62,872	56,023	48,593	$ 61,220	$ 62,872	$ 56,023
Less: Current portion				729	1,136	3,844
Long-term portion				$ 60,491	$ 61,736	$ 52,179
Reductions to PPE included in ARO revisions	$ (1,500)
Additions To PPE Included In ARO Revisions		$ 2,900	$ 400

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Related Party Transactions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jan. 02, 2015
Related Party Transaction [Line Items]
Notes payable to founder	$ 25,700,000	$ 24,500,000
Total expenditures for land consulting services	$ 133,000	150,000	$ 175,000
Contract termination period without penalty for either party	30 days
Amount of receivable paid				$ 25,500,000
Interest rate on note receivable	8.00%
Contributions	$ 20,000,000
Interest Income On Notes Receivable	713,000
Receivable due from affiliate	1,053,000	25,500,000
Non-cash land acquisition from affiliate	700,000
Other Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant	25,500,000
Long Term Note Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant	8,500,000
Vice President, Facilities and Midstream [Member]
Related Party Transaction [Line Items]
Total compensation	275,000	450,000	390,000
Landman [Member]
Related Party Transaction [Line Items]
Total compensation	146,000	260,000	125,000
Founder [Member]
Related Party Transaction [Line Items]
Distributions	$ 0	$ 516,500	$ 17,500
Notes Payable To Founder [Member]
Related Party Transaction [Line Items]
Effective rate of interest on senior notes	10.00%	10.00%
ARM Energy Management, LLC [Member]
Related Party Transaction [Line Items]
Marketing fee	1.00%
ARM Energy Management, LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Percentage of ownership interest	10.00%

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Long Term Debt (Narrative) (Details)		6 Months Ended	9 Months Ended	12 Months Ended
	Feb. 03, 2016 USD ($)	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Mar. 16, 2016 USD ($)	Nov. 01, 2015 USD ($)	Oct. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Sep. 29, 2015 USD ($)	Jun. 02, 2015 USD ($)	Jun. 01, 2015 USD ($)
Debt Instrument [Line Items]
Letter of credit outstanding				$ 65,000	$ 900,000
Face value of senior notes issued				450,000,000
Notes payable to founder				25,748,000	24,540,000
Interest on notes payable to founder				1,208,000	1,209,000	$ 1,208,000
Amortization of deferred financing costs				$ 3,392,000	2,885,000	2,839,000
Debt covenant compliance description				At December 31, 2015, we were in compliance with the covenants of our loan agreements.
Debt restrictive covenants description				The credit facility, Term Loan Facility and senior notes also contain restrictive covenants that limit our ability to, among other things, incur or guarantee additional debt, make distributions (except distributions equal to the amount of income tax liabilities), repay subordinated debt prior to its maturity, grant additional liens on our assets, enter into transactions with our affiliates, enter into hedging transactions with non-lender hedge counterparties, repurchase equity securities, make certain investments or acquisitions of substantially all or a portion of another entity's business assets, and merge with another entity of dispose of any material assets.
Deferred financing costs				$ 1,199,000	1,634,000
Amortization of deferred financing costs				$ 3,400,000	$ 2,900,000	2,800,000
Debt Instrument, Customary events of default				The credit facility, Term Loan Facility and senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.
6th Amended And Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility borrowing base				$ 152,000,000
Credit Facility, Term Loan Facility, And Senior Notes [Member]
Debt Instrument [Line Items]
Deferred financing costs				9,000,000
Term Loan Facility And Senior Notes [Member]
Debt Instrument [Line Items]
Deferred financing costs				$ 7,800,000
Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Collateral				The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves.
Credit facility borrowing base									$ 255,000,000
Line of Credit Facility, Remaining borrowing capacity				$ 0
Date of maturity of credit facility					May 23, 2016
Credit facility interest rate				2.87%	2.89%		3.25%
Letter of credit outstanding							$ 6,100,000
Minimum Working Capital Ratio				1.0
Minimum Coverage of Interest Expense Ratio				3.0
Maximum Leverage Ratio				4.00
Debt instrument collateral				The principal amount is payable at maturity. On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the "Twelfth Amendment") to amend the credit facility to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility. As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million. Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility. The credit facility borrowing base is redetermined semi-annually on or about May 1 and November 1 of each year. In November 2015, the lenders under the credit facility approved an increase in the borrowing base from $255 million to $300 million as part of the semi-annual redetermination. The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves.
Debt covenants description				The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expense of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense ("EBITDAX", as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.
Deferred financing costs				$ 1,200,000
Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description				LIBOR plus applicable margins between 2.00% and 2.75%
Credit Facility [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description				prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%
Credit Facility [Member] | 6th Amended And Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining borrowing capacity				$ 148,000,000
Credit Facility [Member] | 11th Amendment [Member]
Debt Instrument [Line Items]
Credit facility borrowing base												$ 300,000,000	$ 375,000,000
Date of maturity of credit facility				Oct. 13, 2017
Credit Facility [Member] | 12th Amendment [Member]
Debt Instrument [Line Items]
Credit facility borrowing base								$ 300,000,000		$ 255,000,000	$ 300,000,000
Credit Facility [Member] | 13th Amendment [Member]
Debt Instrument [Line Items]
Excess cash transferred	$ 25,000,000
Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate				2.00%
Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate				1.00%
Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate				2.75%
Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate				1.75%
Subsequent Event [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility borrowing base							$ 141,900,000
Scenario, Forecast [Member] | Credit Facility [Member] | 13th Amendment [Member]
Debt Instrument [Line Items]
Maximum Leverage Ratio		4.00	4.50
Senior Notes [Member]
Debt Instrument [Line Items]
Face value of senior notes issued				$ 450,000,000
Maturity date of debt				Oct. 15, 2018
Stated interest rate of senior notes				9.625%
Effective rate of interest				9.7825%
Senior notes interest payable date				Interest is payable semi-annually each April 15th and October 15th.
Debt instrument collateral				The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility and the Term Loan Facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.
Remaining unamortized discount				$ 1,400,000	$ 1,900,000
Redemption price due to specific change of control events				101.00%
Senior Notes [Member] | Twelve Mos Beginning October 15, 2015 [Member]
Debt Instrument [Line Items]
Optional redemption price of Senior Notes				102.406%
Senior Notes [Member] | Twelve Mos Beginning October 15, 2016 [Member]
Debt Instrument [Line Items]
Optional redemption price of Senior Notes				100.00%
Notes Payable To Founder [Member]
Debt Instrument [Line Items]
Maturity date of debt				Dec. 31, 2021	Dec. 31, 2018
Effective rate of interest				10.00%	10.00%
Debt instrument collateral				These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 15, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.
Notes payable to founder				$ 25,700,000	$ 24,500,000
Interest on notes payable to founder				$ 1,200,000	$ 1,200,000	$ 1,200,000
Senior Secured Term Loan [Member]
Debt Instrument [Line Items]
Minimum Working Capital Ratio				1.0
Maximum Debt To EBITDAX Ratio				4.5
Minimum PV-9 Of Total Proved Reserves To Total Secured Debt Ratio				1.5
Minimum EBITDAX To Interest Expense Ratio				2.5
Amount borrowed				$ 125,000,000								125,000,000
Additional borrowings allowed												$ 50,000,000
Period following closing additional borrowings can be made				1 year
Net proceeds used to pay down outstanding amounts under existing credit facility				$ 121,000,000
Mandatory prepayments of percentage of net cash proceeds from asset sales				75.00%
Maturity date of debt				Apr. 15, 2018
Senior Secured Term Loan [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate				8.00%
Senior Secured Term Loan [Member] | Minimum [Member]
Debt Instrument [Line Items]
Mandatory prepayments of percentage of net cash proceeds from asset sales				1.00%
Senior Secured Term Loan [Member] | Maximum [Member]
Debt Instrument [Line Items]
Premium percentage prepayments are subject to				3.00%
Senior Secured Term Loan [Member] | Subsequent Event [Member] | 1st Amendment [Member]
Debt Instrument [Line Items]
Excess cash transferred	$ 25,000,000
Senior Secured Term Loan [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Maximum Leverage Ratio		4.50	5.00

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Long Term Debt (Long-Term Debt And Notes Payable To Founder) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long Term Debt [Abstract]
Credit Facility	$ 152,000	$ 319,520
Senior Notes, net of discount	448,598	448,088
Unamortized Deferred Financing Cost	(7,823)	(6,466)
Total long-term debt	717,775	761,142
Notes payable to founder	$ 25,748	$ 24,540

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Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Summary of future maturities of long-term debt
2016
2017	$ 152,000
2018	$ 575,000
2019
2020
Thereafter	$ 25,748
Total long-term debt	$ 752,748

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Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts Payable And Accrued Liabilities [Abstract]
Capital expenditures	$ 10,780	$ 32,990
Revenues and royalties payable	5,082	7,302
Operating expenses/taxes	19,336	20,716
Interest	9,919	9,136
Compensation	5,434	10,586
Derivatives Settlement Payable	11,149	2,344
Other	1,201	261
Total accrued liabilities	62,901	83,335
Accounts payable	21,101	34,225
Accounts payable and accrued liabilities	$ 84,002	$ 117,560

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Commitments and Contingencies (Details) $ / shares in Units, $ in Thousands		12 Months Ended
	Jan. 01, 2016 $ / shares shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jul. 24, 2013 item
Commitment And Contingencies [Line Items]
Liability for soil contamination | $		$ 1,300	$ 1,100
Vesting period, PARs		5 years
Weighted average stipulated price of PARs granted | $ / shares		$ 32.34
Number of performance appreciation rights granted		0
Number of performance appreciation rights terminated		30,000
Number of performance appreciation rights		241,500
Weighted average price of PARs terminated | $ / shares	$ 40	$ 40
Other long-term litigation liabilities | $		$ 10,829	6,457
Payment under contingent commitment towards properties acquired | $		2,200
Rent expense | $		4,800	$ 5,700	$ 5,300
Performance Bonds Outstanding | $		$ 24,400
Subsequent Event [Member]
Commitment And Contingencies [Line Items]
Weighted average stipulated price of PARs granted | $ / shares	$ 36.91
Number of performance appreciation rights granted	360,000
Number of performance appreciation rights terminated	3,500
Number of performance appreciation rights	598,000
Weighted average price of PARs terminated | $ / shares	$ 40
Building [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases		The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.
Upstream Equipment [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases		Equipment leases are generally for four years or less
Upstream Equipment [Member] | Maximum [Member]
Commitment And Contingencies [Line Items]
Term of leases		4 years
Meridian Resource Company, L L C [Member] | Board Of Commissioners Of Southeast Louisiana Flood Protection Authority - East [Member]
Commitment And Contingencies [Line Items]
Number of wells | item					32
Number of dredging permits | item					2
Number of right of way agreements | item					4

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Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Future base rentals for non-cancelable leases
2015	$ 4,130
2016	2,899
2017	1,574
2018	1,580
2019	1,593
Thereafter	2,827
Total future base rental	$ 14,603

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Major Customers (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) customer	Dec. 31, 2014 USD ($) customer	Dec. 31, 2013 USD ($)
Revenue, Major Customer [Line Items]
Revenues	$ 48,325	$ 61,344	$ 71,755	$ 60,542	$ 87,462	$ 125,644	$ 115,590	$ 103,432	$ 433,888	$ 616,207	$ 355,792
Number of customers that accounted for 10% or more of revenues | customer									1	3
Minimum percentage of contribution of customers to revenue									10.00%	10.00%
Benchmark for determining customer significance									revenues excluding hedging activities
ARM Energy Management, LLC [Member]
Revenue, Major Customer [Line Items]
Marketing fee									1.00%
Term of agreement left until extensions may come into effect									5 years
Revenues									$ 178,200	$ 220,900	$ 61,300
Concentration Risk, Percentage									73.90%	51.10%	16.00%
ARM Energy Management, LLC [Member] | Maximum [Member]
Revenue, Major Customer [Line Items]
Percentage of ownership interest	10.00%								10.00%
Murphy [Member]
Revenue, Major Customer [Line Items]
Revenues										$ 61,200	$ 119,300
Shell Trading (US) Company [Member]
Revenue, Major Customer [Line Items]
Revenues											53,900
Plains Marketing And Transportation, Inc. [Member]
Revenue, Major Customer [Line Items]
Revenues											$ 42,000

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401(k) Savings Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Savings Plan [Abstract]
Percentage of matching contribution by company	50.00%
Maximum percentage of employee's salary deferral contribution	8.00%
Matching contributions to the plan	$ 710,000	$ 683,000	$ 585,000

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Significant Risks And Uncertainties (Details)	12 Months Ended
	Dec. 31, 2015
Significant Risks And Uncertainties [Abstract]
Risks and uncertainties inherent	Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and 2015 and have declined dramatically since the second half of 2014. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2016. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

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Partners' Capital (Deficit) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) item
Number of classes of limited partners | item	2
Amount of recapitalization	$ 350,000
Number of members added to Board of Directors, nominated by Highbridge | item	1
Number of members added to Board of Directors, nominated by Class A partners | item	4
Contributions	$ 20,000
Limited Partner [Member]
Distributions	3,800
Contributions	$ 20,000

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Subsequent Events (Details)	Mar. 08, 2016 USD ($) item	Jan. 13, 2016 USD ($) item	Mar. 16, 2016 USD ($)	Dec. 31, 2015 USD ($)	Oct. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Subsequent Event [Line Items]
Letter of credit outstanding				$ 65,000		$ 900,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Percent commited to fund		100.00%
Total cost of drilling		$ 64,000,000
Credit Facility [Member]
Subsequent Event [Line Items]
Credit facility borrowing base					$ 255,000,000
Credit facility amount			$ 300,000,000
Letter of credit outstanding			$ 6,100,000
Line of Credit Facility, Remaining borrowing capacity				$ 0
Credit facility interest rate			3.25%	2.87%		2.89%
Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Credit facility borrowing base			$ 141,900,000
Joint Development Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Number of well locations | item		40
Number of tranches | item		2
Number of wells | item		20
Joint Development Agreement Tranch 1 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Percent of working interest		80.00%
Percent of interest reduced		20.00%
Percent of internal return rate		15.00%
Joint Development Agreement Tranch 2 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Percent of interest reduced		7.50%
Percent of internal return rate		25.00%
Joint Development Agreement Tranch 3 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Additional number of wells | item	20
Additional cost of drilling	$ 64,000,000

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Supplemental Quarterly Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Quarterly Information [Abstract]
Revenues	$ 48,325	$ 61,344	$ 71,755	$ 60,542	$ 87,462	$ 125,644	$ 115,590	$ 103,432	$ 433,888	$ 616,207	$ 355,792
Income (loss) from operations	(60,592)	110,069	(23,881)	(95,077)	35,873	73,025	(25,186)	71,461	(69,481)	155,173	(98,651)
Net income (loss)	(76,152)	93,079	$ (39,509)	(109,211)	21,793	59,326	$ (38,812)	56,893	(131,793)	99,200	(153,715)
Gain on sale of asset		66,400				$ 18,300		73,100	67,781	87,520	(2,715)
Impairment expense	$ 90,500	$ 8,900		$ 73,100	$ 8,700			$ 18,300	$ 176,774	$ 74,927	$ 143,166

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Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details)	12 Months Ended
	Dec. 31, 2015 MMcf MBbls	Dec. 31, 2014 MMcf MBbls	Dec. 31, 2013 MMcf MBbls
Oil [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	31,344	32,517	20,620
Production	(4,203)	(3,770)	(2,897)
Purchases in place		610	1,462
Discoveries and extensions	12,981	13,281	14,541
Sales of reserves in place	(6,544)	(6,298)	(13)
Revisions of previous quantity estimates and other	564	(4,996)	(1,196)
Proved Reserves, Ending balance	34,142	31,344	32,517
Developed Reserves	14,942	15,182	16,335
Proved Undeveloped Reserves	19,200	16,162	16,182
Natural Gas in MMcf [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance | MMcf	103,148	132,265	152,489
Production | MMcf	(11,900)	(14,449)	(16,664)
Purchases in place | MMcf		327	1,265
Discoveries and extensions | MMcf	58,129	28,822	29,012
Sales of reserves in place | MMcf	(8,250)	(35,857)	(10,912)
Revisions of previous quantity estimates and other | MMcf	14,296	(7,960)	(22,925)
Proved Reserves, Ending balance | MMcf	155,423	103,148	132,265
Developed Reserves | MMcf	71,752	63,334	92,640
Proved Undeveloped Reserves | MMcf	83,671	39,814	39,625
Natural Gas Liquids [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	8,388	5,735	5,695
Production	(678)	(537)	(398)
Discoveries and extensions	7,763	4,119	1,969
Sales of reserves in place	(748)	(949)
Revisions of previous quantity estimates and other	3,712	20	(1,531)
Proved Reserves, Ending balance	18,437	8,388	5,735
Developed Reserves	6,958	4,028	3,138
Proved Undeveloped Reserves	11,479	4,360	2,597
Barrels of Oil Equivalent [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	56,923	60,296	51,731
Production	(6,865)	(6,715)	(6,072)
Purchases in place		665	1,673
Discoveries and extensions	30,432	22,204	21,345
Sales of reserves in place	(8,667)	(13,223)	(1,832)
Revisions of previous quantity estimates and other	6,660	(6,304)	(6,549)
Proved Reserves, Ending balance	78,483	56,923	60,296
Developed Reserves	33,859	29,765	34,913
Proved Undeveloped Reserves	44,624	27,158	25,383

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Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized costs:
Proved properties	$ 1,345,482	$ 1,417,785
Unproved properties	127,551	84,620
Total	1,473,033	1,502,405
Accumulated depreciation, depletion, amortization and impairment	(947,091)	(816,229)
TOTAL OIL AND NATURAL GAS PROPERTIES, net	$ 525,942	$ 686,176

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Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Property acquisition costs, unproved properties		$ 74,475	$ 33,787	$ 34,884
Property acquisition costs, proved properties	[1]	2,899	7,462	35,954
Costs incurred, exploration		34,275	59,201	55,300
Costs incurred, development	[2]	146,299	341,594	242,912
Costs Incurred, Total		257,948	442,044	369,050
Costs Incurred, Additional Information [Abstract]
Development Costs Incurred As Asset Retirement Obligations		(300)	4,500	$ 1,400
Unproved Leasehold Acquisition Cost		$ 46,600
Stone [Member]
Costs Incurred, Additional Information [Abstract]
Total cost of Business Acquisition			$ 30,600

[1] Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million. Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million.

[2] Includes asset retirement additions (revisions) of ($0.3) million, $4.5 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

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Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) $ / Mcf $ / bbl	Dec. 31, 2014 USD ($) $ / Mcf $ / bbl	Dec. 31, 2013 USD ($) $ / Mcf $ / bbl	Dec. 31, 2012 USD ($)
Components of the standardized measure of discounted future net cash flows
Future cash flows	$ 2,395,128	$ 3,737,412	$ 3,959,938
Future production costs	(860,600)	(991,149)	(1,146,123)
Future development costs	$ (403,953)	$ (450,659)	$ (474,191)
Future taxes on income
Future net cash flows	$ 1,130,575	$ 2,295,604	$ 2,339,624
Discount to present value at 10 percent per annum	(500,979)	(877,558)	(933,350)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 629,596	$ 1,418,046	$ 1,406,274	$ 914,421
Base price for crude oil, per Bbl, in the above computations was | $ / bbl	50.28	94.99	96.78
Base price for natural gas, per Mcf, in the above computations was | $ / Mcf	2.58	4.35	3.67

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Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of changes in standardized measure of discounted future net cash flows
Balance at beginning of year	$ 1,418,046	$ 1,406,274	$ 914,421
Sales of oil and natural gas, net of production costs	(147,906)	(320,130)	(263,952)
Changes in sales and transfer prices, net of production costs	(823,073)	(153,770)	69,609
Revisions of previous quantity estimates	53,101	(477,377)	(150,634)
Purchases of reserves-in-place		21,633	93,877
Sales of reserves-in-place	(244,251)	(107,414)	(11,193)
Current year discoveries and extensions	260,078	701,820	621,832
Changes in estimated future development costs	4,376	2,591	11,623
Development costs incurred during the year	42,420	161,357	75,973
Accretion of discount	$ 141,805	$ 140,627	$ 91,442
Net change in income taxes
Change in production rate (timing) and other	$ (75,000)	$ 42,435	$ (46,724)
Net change	(788,450)	11,772	491,853
Balance at end of year	$ 629,596	$ 1,418,046	$ 1,406,274