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10-K

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2015



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



For the transition period from		to

Commission file number 001-34574

Matador Resources Company

(Exact name of registrant as specified in its charter)



Texas		27-4662601
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5400 LBJ Freeway, Suite 1500 Dallas, Texas 75240		75240
(Address of principal executive offices)		(Zip Code)



	Registrant’s telephone number, including area code: (972) 371-5200

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



	Title of each class		Name of each exchange on which registered
	Common Stock, par value $0.01 per share		New York Stock Exchange

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 ý 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 ý

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No ý

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,861,025,900.

As of February 25, 2016, there were 85,801,633 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2016 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

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MATADOR RESOURCES COMPANY

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015

TABLE OF CONTENTS




		Page
PART I
ITEM 1.	BUSINESS	2
ITEM 1A.	RISK FACTORS	30
ITEM 1B.	UNRESOLVED STAFF COMMENTS	49
ITEM 2.	PROPERTIES	49
ITEM 3.	LEGAL PROCEEDINGS	49
ITEM 4.	MINE SAFETY DISCLOSURES	49

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	50
ITEM 6.	SELECTED FINANCIAL DATA	53
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	55
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	74
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	75
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	75
ITEM 9A.	CONTROLS AND PROCEDURES	75
ITEM 9B.	OTHER INFORMATION	78

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	78
ITEM 11.	EXECUTIVE COMPENSATION	78
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	78
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	78
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	78

PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	79

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, sufficient cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions, including the integration of Harvey E. Yates Company, with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the United States Securities and Exchange Commission, or the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:


•	our business strategy;


•	our reserves;


•	our technology;


•	our cash flows and liquidity;


•	our financial strategy, budget, projections and operating results;


•	our oil and natural gas realized prices;


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


•	the availability of drilling and production equipment;


•	the availability of oil field labor;


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


•	the availability and terms of capital;


•	our drilling of wells;


•	our ability to negotiate and consummate acquisition and divestiture opportunities;


•	government regulation and taxation of the oil and natural gas industry;


•	our marketing of oil and natural gas;


•	our exploitation projects or property acquisitions;


•	the integration of acquisitions, including the integration of Harvey E. Yates Company, with our business;


•	our ability to construct and operate midstream facilities;


•	our costs of exploiting and developing our properties and conducting other operations;


•	general economic conditions;


•	competition in the oil and natural gas industry;


•	the effectiveness of our risk management and hedging activities;


•	environmental liabilities;


•	counterparty credit risk;


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


•	our future operating results;


•	estimated future reserves and the present value thereof; and


•	our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty

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as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

PART I

Item 1. Business.

In this Annual Report on Form 10-K, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K.

General

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies:


•	focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas;


•	identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties;


•	continue to improve operational and cost efficiencies;


•	identify and develop midstream opportunities that support and enhance our exploration and development activities;

•maintain our financial discipline; and

•pursue opportunistic acquisitions and divestitures.

Despite a challenging commodity price environment in 2015, the successful execution of our business strategies led to significant increases in our oil and natural gas production and proved oil and natural gas reserves in 2015. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2015, including our merger with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., which added substantially to our Delaware Basin acreage position, our first issuance of senior unsecured notes, an equity offering and the sale of a portion of our midstream assets in Loving County, Texas to an affiliate of EnLink Midstream Partners, LP (“EnLink”). These transactions increased our operational flexibility and further strengthened our balance sheet.

2015 Highlights

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2015, we achieved record oil, natural gas and average daily oil equivalent production. In 2015, we produced 4.5 million Bbl of oil, an increase of 35%, as compared to 3.3 million Bbl of oil produced in 2014. We also produced 27.7 Bcf of natural gas, an increase of 81% from 15.3 billion Bcf of natural gas produced in 2014. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, including 12,306 Bbl of oil per

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day and 75.9 MMcf of natural gas per day, an increase of 55%, as compared to 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, for the year ended December 31, 2014. The increase in oil production was primarily attributable to our ongoing delineation and development operations in the Delaware Basin throughout 2015, as well as our development activities in the Eagle Ford shale during early 2015. The increase in natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production in our Elm Grove properties in Northwest Louisiana in the latter half of 2014 and throughout 2015, but also includes increased natural gas production associated with our operations in both the Delaware Basin and the Eagle Ford shale. Oil production comprised 49% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2015, as compared to 57% for the year ended December 31, 2014.

Increased Oil and Oil Equivalent Reserves

At December 31, 2015, our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, which is an increase of 24% from December 31, 2014. The associated PV-10 of our estimated total proved oil and natural gas reserves decreased 48% to $541.6 million at December 31, 2015 from $1.04 billion at December 31, 2014, as a result of declining oil and natural gas prices throughout 2015. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”

Our proved oil reserves grew 89% to 45.6 million Bbl at December 31, 2015 from 24.2 million Bbl at December 31, 2014. This growth in oil reserves was primarily attributable to our drilling program in the Delaware Basin during 2015. Our proved natural gas reserves decreased 11% to 236.9 Bcf at December 31, 2015 from 267.1 Bcf at December 31, 2014. This decrease in proved natural gas reserves was largely attributable to a decrease in our proved undeveloped natural gas reserves, principally from the reclassification of proved undeveloped natural gas reserves to contingent resources, primarily in the Haynesville shale, as a result of the decline in natural gas prices during 2015 as noted below in “— Estimated Proved Reserves.” As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by Matador or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.

At December 31, 2015, proved developed reserves included 17.1 million Bbl of oil and 101.4 Bcf of natural gas, and proved undeveloped reserves included 28.5 million Bbl of oil and 135.5 Bcf of natural gas. Proved developed reserves comprised 40% and proved oil reserves comprised 54% of our total proved oil and natural gas reserves, respectively, at December 31, 2015. Proved developed reserves comprised 45% of our total reserves and proved oil reserves comprised 35% of our total proved oil and natural gas reserves, respectively, at December 31, 2014.

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past two years, as we continued to apply there what we learned from our Eagle Ford shale, as well as from our Haynesville shale, experience. The Delaware Basin will continue to be our primary area of focus in 2016.

We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin in 2015, including 27 gross (23.7 net) operated and 14 gross (1.3 net) non-operated wells. We also substantially increased our acreage position in the Delaware Basin during 2015. As a result, at December 31, 2015 our total acreage position in the Delaware Basin had increased to approximately 157,100 gross (88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main prospect areas in the Delaware Basin—the Wolf and Jackson Trust prospect areas in Loving County, Texas, the Rustler Breaks and Arrowhead prospect areas in Eddy County, New Mexico and the Ranger and Twin Lakes prospect areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin grew 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, in 2014 to an average daily oil equivalent production of 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, in 2015. We expect our Delaware Basin production to increase throughout 2016 as we continue the delineation and development of these properties.

During 2015, we made significant progress in reducing drilling costs and times for both Wolfcamp and Bone Spring horizontal wells in the Delaware Basin. Our focus on improving drilling times and operational efficiencies has cut drilling

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times by as much as 50% or more on recent Wolfcamp wells in the Wolf and Rustler Breaks prospect areas as compared to earlier wells drilled in those prospect areas. In the Wolf prospect area in Loving County, Texas, for example, Wolfcamp drilling times (spud to total depth) have been reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. In the Rustler Breaks prospect area in Eddy County, New Mexico, where the Wolfcamp formation is shallower, Wolfcamp drilling times have been reduced from an average of 32 days in 2014 and early 2015 to as low as 15 days on recent wells drilled in late 2015. In addition, our most recent Second Bone Spring horizontal well in our Rustler Breaks prospect area was drilled from spud to total depth in 12 days, making it the fastest Second Bone Spring horizontal well we have drilled to date. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and starting to drill wells in “batch” mode in some areas, particularly in the Wolf prospect area where we are in development mode.

These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in 2015. Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million, including production facilities and other related infrastructure. In the Rustler Breaks prospect area, we expect to drill and complete Wolfcamp wells for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure. Our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in these areas. We plan to continue to focus on improving operational efficiencies as we move closer to full development of our Delaware Basin assets.

We completed and began producing oil and natural gas from 18 gross (17.3 net) wells in the Eagle Ford shale in 2015, all in the early portion of the year, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well. During the second quarter of 2015, we concluded our drilling and completion operations in the Eagle Ford for 2015 and did not drill or complete any additional operated wells in the Eagle Ford shale for the remainder of 2015.

We did not drill any operated Haynesville shale wells during 2015, but we did participate in 22 gross (1.9 net) non-operated wells drilled in the Haynesville shale in Northwest Louisiana. The most impactful of these were the Haynesville wells drilled and completed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove properties in southern Caddo Parish. In 2015, Chesapeake completed and placed on production nine gross (1.6 net) wells at Elm Grove. As a result of these 2015 completions and additional non-operated Haynesville wells completed and placed on production in the latter half of 2014, our Haynesville natural gas production grew 135% from 19.7 MMcf of natural gas per day in 2014 to 46.4 MMcf of natural gas per day in 2015.

Financing Arrangements

On April 14, 2015, we issued $400.0 million of 6.875% senior unsecured notes due 2023 in a private placement and, on October 21, 2015, we exchanged all of the privately placed senior notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act. On April 21, 2015, we completed a public offering of 7,000,000 shares of our common stock. After deducting offering costs totaling approximately $1.2 million, we received net proceeds of approximately $187.6 million. Finally, during the fourth quarter of 2015, the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2015, reaffirmed our borrowing base at $375.0 million and extended the maturity date of the credit facility to October 16, 2020. See Note 6 to the consolidated financial statements in this Annual Report on Form 10-K for more details on each of the above items.

Acquisitions and Divestitures

On February 27, 2015, we completed a business combination pursuant to which one of our wholly-owned subsidiaries merged with HEYCO (the “HEYCO Merger”), combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico with our Delaware Basin operations. In the HEYCO Merger, we obtained approximately 58,600 gross (18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the HEYCO Merger.

We also acquired approximately 1,900 net acres contributed into two joint ventures with certain affiliates of HEYCO Energy Group, Inc. We have agreed to contribute an aggregate of approximately $14 million in exchange for a 50% interest in both entities. See Note 16 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the joint ventures.

On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County System”) to EnLink. The Loving County System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the

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“Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects our gathering system to the Processing Plant. Pursuant to the terms of the transaction, EnLink paid cash consideration of approximately $143.4 million, excluding customary purchase price adjustments, and we dedicated our leasehold interests in Loving County as of the closing date pursuant to a 15-year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 5 and Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding the transaction with EnLink.

Principal Areas of Interest

Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2015, we devoted most of our efforts and most of our capital investment to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale in South Texas, although we completed our planned operated drilling and completion activities in the Eagle Ford shale for 2015 in the second quarter. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2015, essentially all of our efforts were focused on unconventional plays.

At December 31, 2015, our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas, and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas.

The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2015.



			Producing		Total Identified		Estimated Net Proved
			Wells		Drilling Locations ⁽¹⁾		Reserves ⁽²⁾		Avg. Daily
	Gross	Net	Gross	Net	Gross	Net		%	Production
	Acreage	Acreage	Gross	Net	Gross	Net	MBOE ⁽³⁾	Developed	(BOE/d) ⁽³⁾
Southeast New Mexico/West Texas:
Delaware Basin ⁽⁴⁾	157,133	88,750	256	96.0	3,543	1,416.9	47,124	27.3	6,518
South Texas:
Eagle Ford ⁽⁵⁾	39,035	29,255	134	115.5	260	227.5	19,015	62.5	10,263
Northwest Louisiana/East Texas:
Haynesville	20,707	13,007	198	18.4	448	109.2	18,148	46.3	7,731
Cotton Valley ⁽⁶⁾	21,775	19,185	93	58.4	71	50.1	840	100.0	443
Area Total ⁽⁷⁾	26,663	23,831	291	76.8	519	159.3	18,988	48.7	8,174
Other:
Wyoming, Utah, Idaho	75,674	35,732	—	—	—	—	—	—	—
Total	298,505	177,568	681	288.3	4,322	1,803.7	85,127	40.0	24,955

__________________

(1)

Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2015. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2015, these engineered drilling locations included only 118 gross (71.1 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Delaware Basin, 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 26 gross (9.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formations at December 31, 2015.

(2)

These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplementary Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report on Form 10-K, which is incorporated herein by reference.


(3)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(4)	Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware and Avalon plays on our acreage in the Delaware Basin at December 31, 2015.


(5)	Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(6)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

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(7)	Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company, Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2015, we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2015, we also were the operator for approximately 95% of our Eagle Ford acreage and approximately two-thirds of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake.

While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques.

In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are proven to be the source rocks for oil and natural gas produced in the basin. Historically, production has come from the “conventional” reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.

We substantially increased our acreage position in the Delaware Basin during 2015, and as a result, at December 31, 2015, our total acreage position in Southeast New Mexico and West Texas had increased to approximately 157,100 gross (88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,100 gross (19,400 net) acres in our Ranger prospect area in Lea County, 47,400 gross (16,900 net) acres in our Arrowhead prospect area in Eddy County, 20,700 gross (13,400 net) acres in our Rustler Breaks prospect area in Eddy County, 12,200 gross (7,500 net) acres in our Wolf and Jackson Trust prospect areas in Loving County and 42,300 gross (29,900 net) acres in our Twin Lakes prospect area in Lea County at December 31, 2015. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2015, our acreage position in the Delaware Basin was approximately 35% held by existing production, including substantially all of the acreage acquired in the HEYCO Merger.

During the year ended December 31, 2015, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin, including 27 gross (23.7 net) operated wells and 14 gross (1.3 net) non-operated wells, throughout our various prospect areas. At December 31, 2015, we had tested a number of different producing horizons at various locations across our acreage position,

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including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, two benches of the Wolfcamp B and the Wolfcamp D. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B.

In our Wolf prospect area in Loving County, Texas, we made significant progress in reducing drilling costs and times for Wolfcamp horizontal wells during 2015. Our focus on improving drilling times and operational efficiencies cut drilling times by as much as 58% on Wolfcamp wells drilled in late 2015 in the Wolf prospect area as compared to earlier wells drilled in this area. Wolfcamp drilling times (spud to total depth) were reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and drilling wells in “batch” mode in the Wolf prospect area where we are in development mode. These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in the Wolf prospect area in 2015. Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million in late 2015, including production facilities and related infrastructure costs. At December 31, 2015, we were conducting multi-well pad operations on two separate leases in our Wolf prospect area with one rig drilling a four-well horizontal stack on the Dick Jay pad and another rig drilling a three-well horizontal stack on our Dorothy White leasehold.

We continue to improve our fracture treatment design in the Delaware Basin. In the Wolf prospect area in late October 2015, we tested the use of a fracture stimulation diverting agent in one of our Billy Burt completions in the northwest portion of the Wolf prospect—the Billy Burt 90-TTT-B33 WF #201H. The Billy Burt 90-TTT-B33 WF #201H well was a Wolfcamp A-Y test and has a completed lateral length of 6,725 feet. The diverting agent was used in an effort to improve the efficiency of each fracturing stage and to ensure as many perforation clusters were treated as possible, while simultaneously improving well costs. Breakdown pressures monitored during the fracture treatments on the Billy Burt 90-TTT-B33 WF #201H well indicated that additional perforations were opened and new hydraulic fractures were created after the diverting agent was pumped in various stages of the fracturing operation. The Billy Burt 90-TTT-B33 WF #201H well initially tested about 1,100 BOE per day (68% oil), consisting of about 750 Bbl of oil per day and 2.1 MMcf of natural gas per day. More importantly, however, early production from the well over its initial 90 days was about 27% higher than the immediate 80-acre offsetting well having a similar lateral length, but where no diverting agent was used. We continue to refine and improve our fracture treatments designs, including the use of both existing technologies and new technologies as they become available and are determined to be beneficial, in an effort to improve the overall recovery from our Delaware Basin wells.

We made significant progress with our midstream operations in 2015, particularly in the Wolf prospect area. As noted above in “—2015 Highlights—Acquisitions and Divestitures,” we completed the sale of the Loving County System to EnLink for cash proceeds of approximately $143.4 million, excluding customary purchase price adjustments, on October 1, 2015. At closing, the Processing Plant had been online for only about a month. Although we sold the Loving County System, we retained our infield natural gas gathering system up to a central delivery point and our other midstream assets in the Wolf prospect area, including oil and water gathering systems. We also retained our interest in a commercial salt water disposal facility in Loving County, operated by a joint venture controlled by the Company. During 2015, the joint venture entity disposed of over 5.5 million barrels of salt water, with a total savings to the Company of approximately $6.5 million in salt water disposal costs. In addition, the joint venture entity began disposing of third-party salt water on a commercial basis in the fourth quarter of 2015.

We also made significant progress delineating and testing our acreage position in the Rustler Breaks prospect area in Eddy County, New Mexico in 2015. At December 31, 2014, we had drilled and completed only one well in Rustler Breaks—the Rustler Breaks 12-24S-27E RB #224H (formerly the Rustler Breaks 12-24-27 #1H)—in a single horizon of the Wolfcamp B. By the end of 2015, we had tested four different producing horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—across our Rustler Breaks prospect area from southeast to northwest.

One of the highlights and technical achievements of 2015 was the successful drilling and completion of our first three-zone stacked lateral test on a single drilling pad in the Rustler Breaks prospect area. From this single pad location, we successfully stacked three horizontal wells targeting three different horizons including, from shallowest to deepest, the Second Bone Spring, Wolfcamp A-XY and Wolfcamp B. The Wolfcamp B well (Tiger 14-24S-28E RB #224H) tested 1,533 BOE per day (42% oil), the Wolfcamp A-XY well (Tiger 14-24S-28E RB #204H) tested 1,405 BOE per day (75% oil) and the Second Bone Spring well (Tiger 14-24S-28E RB #124H) tested 702 BOE per day (83% oil). We were encouraged not only by the early results of this important technical advance, but also by the potential further savings that we anticipate can be achieved through the repeatability of this “stacked” pay concept at other locations. We expect to drill and complete Wolfcamp wells in the Rustler Breaks prospect area for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure, and our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in this area.

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In mid-2015, the Scott Walker State 36-22S-27E RB #204H well, a Wolfcamp A-XY completion located in the far northwestern portion of our Rustler Breaks prospect area, was completed using our Generation 2 Wolfcamp fracture treatment design with 2,000 pounds of sand per foot of completed lateral and 30 barrels of fracturing fluid per foot of completed lateral. This well tested 504 BOE per day (70% oil), consisting of 354 Bbl of oil per day and 0.9 MMcf of natural gas per day. Although this well did not test at rates as high as our Wolfcamp A-XY tests in the southeastern part of the Rustler Breaks area—the Guitar 10-24S-28E RB #202H and Tiger 14-24S-28E RB #204H wells—we were encouraged by these results as they established the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. To our knowledge, this is the northernmost horizontal test of the Wolfcamp A-XY to date in Eddy County, New Mexico. In late 2015, we tested the Wolfcamp A-XY close to the center of our Rustler Breaks acreage position using our Generation 3 fracture treatment design with up to 3,000 pounds of sand and 40 barrels of fracturing fluid per foot of completed lateral. This well, the Dr. K 24-23S-27E RB #203H, tested 1,241 BOE per day (69% oil), consisting of 856 Bbl of oil per day and 2.3 MMcf of natural gas per day during its 24-hour initial potential test, which further establishes the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. Also, late in 2015, we completed and placed on production two additional wells from the multi-well pad referenced above. One of these wells was the Janie Conner 13-24S-28E RB #224H, a Wolfcamp B completion, which was also stimulated with increased sand concentrations up to 3,000 pounds of sand per foot of completed lateral. During its 24-hour initial potential test, this well flowed 1,703 BOE per day (59% oil), consisting of 1,005 Bbl of oil per day and 4.2 MMcf of natural gas per day, making it the best 24-hour initial potential test of any well we have drilled thus far in the Delaware Basin.

As noted above in “—2015 Highlights—Acquisitions and Divestitures,” in the HEYCO Merger we obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross (18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. Most of the acreage from the HEYCO Merger is now included primarily in our Arrowhead prospect area in Eddy County, New Mexico and our Ranger prospect area in Lea County, New Mexico. We did not drill and complete any operated wells in our Arrowhead prospect area in 2015, but we did participate in several non-operated horizontal wells in the Arrowhead prospect area subsequent to the HEYCO Merger, which results illustrate the quality and prospectivity of our acreage in this area. We participated in, or acquired through the HEYCO Merger, four wells operated by an affiliate of Concho Resources Inc. in this area, the CTA State Com #3H, #4H, #5H and #6H wells. These wells were Second Bone Spring completions and tested at an average initial production rate of 956 BOE per day (85% oil). We own an approximate 15% working interest in each of these four wells. We also participated with Mewbourne Oil Company, Inc. in its Gobbler 5 B2PM #1H well in the Arrowhead prospect area. This well, a Second Bone Spring completion, tested 2,300 BOE per day (80% oil), and we own a 6% working interest in this well.

In the Ranger prospect area in Lea County, New Mexico, our first two Second Bone Spring completions have performed above our original projections for this area. As of January 2016, the Ranger State 33-20S-35E RN #121 (formerly the Ranger 33 State Com #1H) had produced 238,000 BOE (91% oil) in its first 26 months of production. The Pickard State 20-18S-34E RN #121H (formerly the Pickard State 20-18-34 #1H), also drilled and completed in the Second Bone Spring, had produced 205,000 BOE (89% oil) in its first 18 months of production. We installed gas-lift assist on the Ranger State 33-20S-35E RN #121 well within its first two months of production, and given the early success of the gas-lift assist on that well, the Pickard State 20-18S-34E RN #121H well was also equipped with gas-lift assist within approximately 30 days of being placed on production. The use of gas-lift assist on these wells in the Ranger prospect area is one example of a transfer of technology and lessons learned from our Eagle Ford shale development program in South Texas to the Delaware Basin. Also in the Ranger prospect area, we drilled and completed the Cimarron 16-19S-34E RN #134H well in the Third Bone Spring formation. During its 24-hour initial potential test, the Cimarron 16-19S-34E RN #134H well flowed 804 BOE per day (94% oil), consisting of 754 Bbl of oil per day and 303 Mcf of natural gas per day. Subsequent to this initial potential test, an electric submersible pump (“ESP”) was run in the well to enable it to continue to clean up and produce more efficiently. This was our first use of an ESP in one of our Ranger area wells. After installing the ESP, production from the Cimarron 16-19S-34E RN #134 well increased to over 1,100 BOE per day, and in its first 8.5 months of production as of January 2016, this well produced 123,000 BOE (94% oil). We consider this to be a strong test of the Third Bone Spring, which illustrates the potential for this interval of the Bone Spring as a viable completion target throughout the Ranger prospect area. During 2015, we also participated in a non-operated Second Bone Spring well offsetting our Pickard State 20-18S-34E RN #121H well. This well, the Iggles 21 State Com #1H, tested 1,300 BOE per day (90% oil), again confirming the prospectivity of the Second Bone Spring in our Ranger prospect area.

In our Twin Lakes prospect area in northern Lea County, New Mexico, we drilled a vertical pilot hole in the fourth quarter of 2015 where we gathered a full suite of openhole well logs and both whole core and rotary sidewall core samples in preparation for drilling our first horizontal well in the Twin Lakes area, which is currently planned for late 2016. At December 31, 2015, we were evaluating the data collected from the vertical pilot hole and evaluating several horizons in the Wolfcamp D as potential horizontal landing targets.

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As a result of our ongoing drilling and completion operations in these prospect areas, our Delaware Basin production increased significantly in 2015. Our average daily oil equivalent production from the Delaware Basin increased 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, during 2014 to 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, during 2015. In addition, our average daily oil equivalent production from the Delaware Basin grew more than three-fold from 2,629 BOE per day in the fourth quarter of 2014 to 8,720 BOE per day in the fourth quarter of 2015. For the year ended December 31, 2015, 26% of our daily oil equivalent production was produced from the Delaware Basin. The Delaware Basin contributed approximately 38% of our daily oil production and approximately 15% of our daily natural gas production during 2015, as compared to only approximately 14% of our daily oil production and approximately 7% of our daily natural gas production during 2014. During the year ended December 31, 2014, only approximately 11% of our daily oil equivalent production was attributable to the Delaware Basin.

At December 31, 2015, approximately 56% of our estimated total proved oil and natural gas reserves, or 47.1 million BOE, was attributable to the Delaware Basin, including approximately 31.4 million Bbl of oil and 94.4 Bcf of natural gas, a 3.6-fold increase, as compared to 13.0 million BOE for the year ended December 31, 2014. Our Delaware Basin proved reserves at December 31, 2015 comprised approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves, as compared to approximately 33% of our proved oil reserves and 11% of our proved natural gas reserves at December 31, 2014. The PV-10 of our proved reserves in the Delaware Basin at December 31, 2015 was $314.6 million, or approximately 58% of the PV-10 of our total proved reserves of $541.6 million. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.”

At December 31, 2015, we had identified 3,543 gross (1,416.9 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Avalon and Delaware formations. These locations include 2,263 gross (1,284.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2015 do not yet include all portions of our acreage position, including the acreage associated with our Twin Lakes prospect area in Lea County, New Mexico. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2015, these potential future drilling locations included only 118 gross (71.1 net) locations in the Delaware Basin to which we have assigned proved undeveloped reserves.

At December 31, 2015 and February 25, 2016, we were operating three drilling rigs in the Delaware Basin—two in Loving County, Texas and one in Eddy County, New Mexico. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated approximately $315.0 million, or approximately 97% of our 2016 capital expenditure budget of $325.0 million, to our anticipated drilling, completion and midstream activities in the Delaware Basin, as well as for the acquisition of additional leasehold interests in the area. Our 2016 Delaware Basin drilling and completion program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of our Ranger and Arrowhead prospect areas.

South Texas — Eagle Ford Shale and Other Formations

The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate.

At December 31, 2015, our properties included approximately 39,000 gross (29,300 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 82% of our Eagle Ford acreage was held by production at December 31, 2015, and approximately 92% of our Eagle Ford acreage

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was either held by production at December 31, 2015 or not burdened by lease expirations before 2017. In the third quarter of 2015, we acquired approximately 385 gross (385 net) acres in the Eagle Ford shale in Karnes County, Texas adjacent to our Sickenius prospect that we consider to be prospective primarily for oil. We plan to continue our leasing and acquisition efforts in the Eagle Ford shale as strategic opportunities are identified.

At January 1, 2015, we were operating two rigs in the Eagle Ford shale in South Texas, but as a result of both lower oil and natural gas prices in early 2015 and the fact that, at December 31, 2014, approximately 96% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2016, we suspended our operated Eagle Ford drilling and completion operations in the second quarter of 2015.

During the year ended December 31, 2015, we completed and began producing oil and natural gas from 18 gross (17.3 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well, all in the first few months of 2015. During the second quarter of 2015, our Eagle Ford production increased to its all-time high of 11,942 BOE per day, including 9,358 Bbl of oil per day and 15.5 MMcf of natural gas per day. We completed our planned operated Eagle Ford drilling and completion operations for 2015 in the second quarter, and as a result, our Eagle Ford production declined during the second half of 2015. Despite conducting no operated activity for more than half of 2015, our average daily oil equivalent production from the Eagle Ford shale decreased only 2% from 10,501 BOE per day, including 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, during 2014 to 10,263 BOE per day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015. For the year ended December 31, 2015, 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2014, approximately 65% of our daily oil equivalent production was attributable to the Eagle Ford shale.

At December 31, 2015, approximately 22% of our estimated total proved oil and natural gas reserves, or 19.0 million BOE, was attributable to the Eagle Ford shale, including approximately 14.2 million Bbl of oil and 28.8 Bcf of natural gas. Our total proved reserves attributable to the Eagle Ford shale decreased approximately 15% to 19.0 million BOE for the year ended December 31, 2015, as compared to 22.3 million BOE for the year ended December 31, 2014, primarily as a result of declining oil and natural gas prices which resulted in certain previously classified Eagle Ford shale proved undeveloped reserves being reclassified to contingent resources at December 31, 2015. Our Eagle Ford total proved reserves at December 31, 2015 comprised approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves, as compared to approximately 67% of our proved oil reserves and 14% of our proved natural gas reserves at December 31, 2014. The PV-10 of our total proved reserves in the Eagle Ford shale was $175.1 million, or approximately 32% of the PV-10 of our total proved reserves of $541.6 million at December 31, 2015. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.”

We do not plan to drill any operated Eagle Ford shale wells in 2016, but we have allocated approximately $5.6 million, or about 2%, of our 2016 estimated capital expenditure budget of $325.0 million to the Eagle Ford shale primarily to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired.

At December 31, 2015, we had identified 260 gross (227.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate the Eagle Ford wells to be drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. While we do not plan to drill any operated wells in the Eagle Ford in 2016, approximately 92% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2017 at December 31, 2015. As a result, these engineered drilling locations remain available to be developed by us at a future time should commodity prices improve, drilling and completion costs decline further or new technologies be developed that increase the expected recoveries. At December 31, 2015, these 260 gross (227.5 net) identified drilling locations included only 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves.

We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2015, we had not drilled any Buda wells nor had we included any Buda locations in our future drilling locations.

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Northwest Louisiana and East Texas

We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2015, although we did participate in the drilling and completion of 22 gross (1.9 net) non-operated Haynesville shale wells that were turned to sales in 2015. These wells included nine gross (1.6 net) Haynesville wells operated by Chesapeake on our Elm Grove acreage in southern Caddo Parish, Louisiana. In addition, Chesapeake deferred first production until early January 2016 from an additional nine gross (1.9 net) wells drilled and completed in the latter half of 2015 on our Elm Grove acreage. We do not plan to drill any operated Haynesville shale wells in 2016, but we have budgeted capital expenditures of approximately $4.4 million for our anticipated participation in five gross (0.6 net) Haynesville shale wells that we expect to be drilled or completed and placed on production by Chesapeake on certain of our non-operated properties, including Elm Grove, in 2016. Certain of these wells were already in progress at December 31, 2015.

At December 31, 2015, we held approximately 26,700 gross (23,800 net) acres in Northwest Louisiana and East Texas, including 20,700 gross (13,000 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,700 gross (6,800 net) acres that we consider to be in the core area of the Haynesville play.

For the year ended December 31, 2015, approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per day and 48.9 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 64% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2015, as compared to approximately 54% of our daily natural gas production and approximately 0.2% of our daily oil production during 2014. During the year ended December 31, 2014, approximately 24% of our average daily oil equivalent production, or 3,791 BOE per day, including 17 Bbl of oil per day and 22.6 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas.

For the year ended December 31, 2015, approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3%, or 2.6 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2014, approximately 47% of our daily natural gas production, or 19.7 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 7%, or 2.9 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2015, approximately 21% of our estimated total proved reserves, or 18.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.8 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage.

At December 31, 2015, we had identified and engineered 448 gross (109.2 net) locations for potential future drilling in the Haynesville shale play and 71 gross (50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 448 gross (109.2 net) locations identified for future drilling on our Haynesville acreage, 373 gross (55.3 net) locations have been identified within the 13,700 gross (6,800 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2015, these potential future drilling locations included only 26 gross (9.4 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves.

Haynesville and Middle Bossier Shales

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.

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At December 31, 2015, we had approximately 20,700 gross (13,000 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,700 gross (6,800 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2015.

Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%.

Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations

Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas.

All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2015, are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.

We have identified 71 gross (50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2015 and do not plan to drill any of these locations in 2016. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.

We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2015, we held an estimated 11,700 gross (9,300 net) leasehold and mineral acres by existing production in these areas.

Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale

At December 31, 2015, we held leasehold interests in approximately 75,700 gross (35,700 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort on this acreage. We are the operator of this prospect. We have drilled and completed one horizontal well on this acreage, but as of December 31, 2015, we had not established commercial natural gas production on this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2015. We have no plans to drill on this acreage in 2016.

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Operating Summary

The following table sets forth certain unaudited production data for the years ended December 31, 2015, 2014 and 2013.



	Year Ended December 31,
	2015		2014		2013
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl)	4,492		3,320		2,133
Natural gas (Bcf)	27.7		15.3		12.9
Total oil equivalent (MBOE) ⁽¹⁾	9,109		5,870		4,285
Average daily production (BOE/d) ⁽¹⁾	24,955		16,082		11,740
Average Sales Prices:
Oil, with realized derivatives (per Bbl)	$	59.13	$	88.94	$	98.67
Oil, without realized derivatives (per Bbl)	$	45.27	$	87.37	$	99.79
Natural gas, with realized derivatives (per Mcf)	$	3.24	$	5.06	$	4.47
Natural gas, without realized derivatives (per Mcf)	$	2.71	$	5.08	$	4.35
Operating Expenses (per BOE):
Production taxes and marketing	$	3.90	$	5.65	$	4.89
Lease operating	$	6.39	$	8.75	$	9.04
Depletion, depreciation and amortization	$	19.63	$	22.95	$	22.96
General and administrative	$	5.50	$	5.48	$	4.85

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(1)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.



	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Delaware Basin			Eagle Ford ⁽¹⁾			Haynesville			Cotton Valley ⁽²⁾			Total
Annual Net Production Volumes
Oil (MBbl)	1,697			2,789			—			6			4,492
Natural gas (Bcf)	4.1			5.7			16.9			1.0			27.7
Total oil equivalent (MBOE) ⁽³⁾	2,379			3,746			2,822			162			9,109
Percentage of total annual net production	26.1		%	41.1		%	31.0		%	1.8		%	100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)	4,648			7,642			—			16			12,306
Natural gas (MMcf/d)	11.2			15.7			46.4			2.6			75.9
Total oil equivalent (BOE/d)	6,518			10,263			7,731			443			24,955
Average Sales Price⁽⁴⁾
Oil (per Bbl)	$	43.54		$	46.33		$	—		$	43.68		$	45.27
Natural gas (per Mcf)	$	3.00		$	3.17		$	2.49		$	2.45		$	2.71
Total oil equivalent (per BOE)	$	36.21		$	39.35		$	14.97		$	15.69		$	30.56
Production Costs ⁽⁵⁾
Lease operating and marketing (per BOE)	$	9.89		$	9.35		$	4.91		$	19.88		$	8.29

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(1)	Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(2)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.


(3)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(4)	Excludes impact of derivative settlements.


(5)	Excludes ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2014 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.



	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Delaware Basin			Eagle Ford ⁽¹⁾			Haynesville			Cotton Valley ⁽²⁾			Total
Annual Net Production Volumes
Oil (MBbl)	480			2,834			—			6			3,320
Natural gas (Bcf)	1.0			6.0			7.2			1.1			15.3
Total oil equivalent (MBOE) ⁽³⁾	653			3,833			1,201			183			5,870
Percentage of total annual net production	11.1		%	65.3		%	20.5		%	3.1		%	100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)	1,314			7,764			—			17			9,095
Natural gas (MMcf/d)	2.9			16.4			19.7			2.9			41.9
Total oil equivalent (BOE/d)	1,790			10,501			3,290			501			16,082
Average Sales Price⁽⁴⁾
Oil (per Bbl)	$	80.16		$	88.58		$	—		$	91.24		$	87.37
Natural gas (per Mcf)	$	4.75		$	6.72		$	3.87		$	4.30		$	5.08
Total oil equivalent (per BOE)	$	66.41		$	75.99		$	23.27		$	27.92		$	62.64
Production Costs ⁽⁵⁾
Lease operating and marketing (per BOE)	$	13.11		$	10.45		$	8.13		$	19.09		$	10.53

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(1)	Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(2)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.


(3)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(4)	Excludes impact of derivative settlements.


(5)	Excludes ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2013 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.



	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Southeast New Mexico/West Texas			South Texas			Northwest Louisiana/East Texas
	Delaware Basin			Eagle Ford ⁽¹⁾			Haynesville			Cotton Valley ⁽²⁾			Total
Annual Net Production Volumes
Oil (MBbl)	28			2,098			—			6			2,132
Natural gas (Bcf)	—			5.4			6.2			1.3			12.9
Total oil equivalent (MBOE) ⁽³⁾	31			3,002			1,033			219			4,285
Percentage of total annual net production	0.7		%	70.1		%	24.1		%	5.1		%	100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)	78			5,748			—			17			5,843
Natural gas (MMcf/d)	—			14.9			17.0			3.5			35.4
Total oil equivalent (BOE/d)	84			8,225			2,831			600			11,740
Average Sales Price⁽⁴⁾
Oil (per Bbl)	$	90.71		$	99.91		$	—		$	102.13		$	99.79
Natural gas (per Mcf)	$	5.27		$	6.03		$	3.05		$	3.55		$	4.35
Total oil equivalent (per BOE)	$	86.51		$	80.71		$	18.28		$	23.61		$	62.78
Production Costs ⁽⁵⁾
Lease operating and marketing (per BOE)	$	15.68		$	11.65		$	5.24		$	15.39		$	10.30

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(1)	Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(2)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.


(3)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(4)	Excludes impact of derivative settlements.


(5)	Excludes ad valorem taxes and oil and natural gas production taxes.

Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014. This increased production was primarily due to our delineation and development operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended December 31, 2014. Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014. Our average daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014.

Our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 increased 37% from our total oil equivalent production of approximately 4.3 million BOE for the year ended December 31, 2013. This increased production was primarily due to our drilling and completion operations in the Eagle Ford shale, as well as contributions from our initial wells in the Delaware Basin. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, as compared to 11,740 BOE per day for the year ended December 31, 2013. Our average daily oil production for the year ended December 31, 2014 was 9,095 Bbl of oil per day, an increase of 56% from 5,843 Bbl of oil per day for the year ended December 31, 2013. Our average daily natural gas production for the year ended December 31, 2014 was 41.9 MMcf of natural gas per day, an increase of 18% from 35.4 MMcf of natural gas per day for the year ended December 31, 2013.

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Producing Wells

The following table sets forth information relating to producing wells at December 31, 2015. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 69% in all wells that we operate at December 31, 2015, as compared to 93% at December 31, 2014, as a result of acquiring producing wells with lower working interests in the Delaware Basin as part of the HEYCO Merger in February 2015. For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells.



	Oil Wells		Natural Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin ⁽¹⁾	223	84.9	33	11.1	256	96.0
South Texas:
Eagle Ford⁽²⁾	130	111.5	4	4.0	134	115.5
Northwest Louisiana/East Texas:
Haynesville	—	—	198	18.4	198	18.4
Cotton Valley ⁽³⁾	2	2.0	91	56.4	93	58.4
Area Total	2	2.0	289	74.8	291	76.8
Total	355	198.4	326	89.9	681	288.3

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(1)	Includes 175 gross (50.6 net) wells acquired in February 2015 as part of the HEYCO Merger.


(2)	Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(3)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2015, 2014 and 2013. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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	At December 31, ⁽¹⁾
	2015			2014			2013
Estimated Proved Reserves Data: ⁽²⁾
Estimated proved reserves:
Oil (MBbl)	45,644			24,184			16,362
Natural Gas (Bcf) ⁽³⁾	236.9			267.1			212.2
Total (MBOE) ⁽⁴⁾	85,127			68,693			51,729
Estimated proved developed reserves:
Oil (MBbl)	17,129			14,053			8,258
Natural Gas (Bcf) ⁽³⁾	101.4			102.8			53.5
Total (MBOE) ⁽⁴⁾	34,037			31,185			17,168
Percent developed	40.0		%	45.4		%	33.2		%
Estimated proved undeveloped reserves:
Oil (MBbl)	28,515			10,131			8,104
Natural Gas (Bcf) ⁽³⁾	135.5			164.3			158.7
Total (MBOE)⁽⁴⁾	51,090			37,508			34,561
PV-10 ⁽⁵⁾ (in millions)	$	541.6		$	1,043.4		$	655.2
Standardized Measure ⁽⁶⁾ (in millions)	$	529.2		$	913.3		$	578.7

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(1)	Numbers in table may not total due to rounding.

(2)

Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas, and for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.67 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.


(3)	As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale.


(4)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our 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 and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015, 2014 and 2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015, 2014 and 2013 were, in millions, $12.4, $130.1 and $76.5, respectively.


(6)	Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

Our estimated total proved oil and natural gas reserves increased 24% from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015. We added 39.1 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2015, approximately 4.3 times our 2015 annual production of 9.1 million BOE. Our proved oil reserves grew 89% from approximately 24.2 million Bbl at December 31, 2014 to approximately 45.6 million Bbl at December 31, 2015. This increase in proved oil reserves is primarily attributable to our drilling program in the Delaware Basin during 2015. Our proved natural gas reserves decreased 11% from 267.1 Bcf at December 31, 2014 to 236.9 Bcf at December 31, 2015. This decrease in proved natural gas reserves was primarily attributable to a decrease in our proved undeveloped natural gas reserves. As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.

The PV-10 of our total proved oil and natural gas reserves decreased 48% from $1.04 billion at December 31, 2014 to $541.6 million at December 31, 2015, as a result of lower oil and natural gas prices. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2015 were $46.79 per Bbl and $2.59 per MMBtu, a decrease of 49% and 40%, respectively, as compared to average oil and natural gas prices of $91.48 per Bbl and $4.35 per MMBtu used to estimate proved reserves at December 31, 2014. Our total proved reserves at

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December 31, 2015 were made up of approximately 54% oil and 46% natural gas, as compared to 35% oil and 65% natural gas at December 31, 2014.

Our proved developed oil and natural gas reserves increased 9% from 31.2 million BOE at December 31, 2014 to 34.0 million BOE at December 31, 2015 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 22% from 14.1 million Bbl at December 31, 2014 to 17.1 million Bbl at December 31, 2015, also primarily as a result of our delineation and development operations in the Delaware Basin. Our proved developed natural gas reserves decreased 1% from 102.8 Bcf at December 31, 2014 to 101.4 Bcf at December 31, 2015, resulting from downward revisions to certain of our proved developed natural gas reserves, primarily in the Haynesville shale, as a result of sharply lower natural gas prices in 2015, and to the 81% increase in our natural gas production to 27.7 Bcf in 2015 as compared to 15.3 Bcf in 2014.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2015.



	Proved Developed Reserves
	Proved Developed Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2014	31,185
Extensions and discoveries	6,984
Purchases of minerals-in-place	1,180
Revisions of prior estimates	(2,950	)
Production	(9,109	)
Conversion of proved undeveloped to proved developed	6,747
As of December 31, 2015	34,037

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(1)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved undeveloped oil and natural gas reserves increased from 37.5 million BOE at December 31, 2014 to 51.1 million BOE at December 31, 2015. Our proved undeveloped oil reserves increased from 10.1 million Bbl at December 31, 2014 to 28.5 million Bbl at December 31, 2015, primarily as a result of our delineation and development operations in the Delaware Basin. Our proved undeveloped natural gas reserves decreased from 164.3 Bcf at December 31, 2014 to 135.5 Bcf at December 31, 2015 due primarily to the removal of previously classified proved undeveloped natural gas reserves from our total proved reserves, particularly in the Haynesville shale, as a result of lower natural gas prices in 2015, as noted above.

At December 31, 2015, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2015 within five years of booking these reserves.

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2015.



	Proved Undeveloped Reserves
	Proved Undeveloped Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2014	37,508
Extensions and discoveries	32,151
Purchases of minerals-in-place	409
Revisions of prior estimates	(12,231	)
Conversion of proved undeveloped to proved developed	(6,747	)
As of December 31, 2015	51,090

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(1)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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The following table sets forth, since 2012, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).



				Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
	Proved Undeveloped Reserves Converted to Proved Developed Reserves

	Oil	Natural Gas	Total
	(MBbl)	(Bcf)	(MBOE)⁽¹⁾
2012	283	0.8	415	$	8,096
2013	2,944	8.3	4,334	115,699
2014	3,780	44.7	11,223	201,950
2015	2,854	23.4	6,747	104,989
Total	9,861	77.2	22,719	$	430,734

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(1)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2015.



	Net Proved Reserves⁽¹⁾
	Oil	Natural Gas	Oil Equivalent	PV-10 ⁽²⁾		Standardized Measure ⁽³⁾
	(MBbl)	(Bcf)	(MBOE) ⁽⁴⁾	(in millions)		(in millions)
Southeast New Mexico/West Texas:
Delaware Basin	31,395	94.4	47,124	$	314.6	$	307.4
South Texas:
Eagle Ford ⁽⁵⁾	14,221	28.8	19,015	175.1		171.1
Northwest Louisiana/East Texas:
Haynesville	—	108.8	18,148	49.3		48.2
Cotton Valley ⁽⁶⁾	28	4.9	840	2.6		2.5
Area Total	28	113.7	18,988	51.9		50.7
Other:
Wyoming, Utah, Idaho	—	—	—	—		—
Total	45,644	236.9	85,127	$	541.6	$	529.2

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(1)	Numbers in table may not total due to rounding.

(2)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our 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 and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015 were approximately $12.4 million.


(3)	Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.


(4)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.


(5)	Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.


(6)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Technology Used to Establish Reserves

Under current SEC rules, proved 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational

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methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 38 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2015.



	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin	73,494	30,814	83,639	57,936	157,133	88,750
South Texas:
Eagle Ford	28,910	23,431	10,125	5,824	39,035	29,255
Northwest Louisiana/East Texas:
Haynesville	17,343	9,644	3,364	3,363	20,707	13,007
Cotton Valley	18,189	16,111	3,586	3,074	21,775	19,185
Area Total ⁽¹⁾	22,634	20,315	4,030	3,517	26,663	23,831
Other:
Wyoming, Utah, Idaho	1,600	800	74,074	34,932	75,674	35,732
Total	126,638	75,360	171,868	102,209	298,505	177,568

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(1)	Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas.

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2015 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2019 and beyond represents an immaterial amount of our overall undeveloped acreage.

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	Acres		Acres		Acres
	Expiring 2016		Expiring 2017		Expiring 2018
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin ⁽¹⁾	34,235	21,175	17,188	10,336	18,045	14,077
South Texas:
Eagle Ford ⁽²⁾	2,633	2,435	2,510	2,484	477	477
Northwest Louisiana/East Texas:
Haynesville	524	523	—	—	—	—
Cotton Valley	80	80	—	—	—	—
Area Total ⁽³⁾	524	523	—	—	—	—
Other:
Wyoming, Utah, Idaho	—	—	21,874	9,575	48,859	24,605
Total	37,392	24,133	41,572	22,395	67,381	39,159

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(1)

Approximately 60% of the acreage expiring in 2016 is associated with our Twin Lakes prospect area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes prospect area in 2016 through our 2016 drilling activities or by paying an additional lease bonus, where applicable.


(2)	We expect to extend portions of our expiring Eagle Ford acreage in 2016 by paying an additional lease bonus.


(3)	Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2015, our leases are primarily fee and state leases with primary terms of three to five years. As a result of the HEYCO Merger in 2015, we also have acquired a significant number of federal leases with primary terms of 10 years; however, essentially all of the federal leases acquired in the HEYCO Merger are held by production. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

Drilling Results

The following table summarizes our drilling activity for the years ended December 31, 2015, 2014 and 2013.



	Year Ended December 31,
	2015		2014		2013
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	53	26.7	89	39.9	32	20.7
Dry	—	—	—	—	—	—
Exploration Wells
Productive	28	17.5	12	10.6	14	8.7
Dry ⁽¹⁾	—	—	—	—	1	0.4
Total Wells
Productive	81	44.2	101	50.5	46	29.4
Dry ⁽¹⁾	—	—	—	—	1	0.4

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(1) We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013.

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Marketing

Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

For the year ended December 31, 2015, we had three significant purchasers that accounted for approximately 59% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2014 and 2013, we had three and five significant purchasers that accounted for approximately 68% and 87%, respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time.

Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period.

Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, we had an immaterial natural gas deficiency and the counterparty to this agreement waived the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.”

As part of the sale of the Loving County System (See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K), we entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby we committed to deliver the anticipated natural gas production from a significant portion of our Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facility. Under this agreement, if we do not meet the volume commitment for transportation and processing at the facility in a contract year, we will be required

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to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, we can elect to have the previous year’s actual transportation and processing commitment be the new minimum commitment for each of the remaining years of the contract. As such, we have the ability to unilaterally reduce the transportation and processing commitment if our production in the Loving County area is less than our currently projected production. If we ceased operations in this area at December 31, 2015, the total deficiency fee required to be paid would be approximately $9.6 million. In addition, if we elect to reduce the transportation and processing commitment in any year, we have the ability to elect to increase the committed volumes in any future year to the originally agreed transportation and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. We paid approximately $1.8 million in processing and transportation fees under this agreement during the year ended December 31, 2015. We can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to us the residue gas in-kind to be sold to third parties downstream of the plant. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.”

Title to Properties

We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.”

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations.

Competition

The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.

Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.”

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Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations.

Texas, New Mexico, Louisiana, Wyoming, Idaho, Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. 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.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. 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, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.

In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.

Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.

The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.

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In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.”

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage).

Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.

While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters.

Environmental Regulation

The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations.

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We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation.

RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil

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and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Since January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. Further, in August 2015, the EPA issued proposed NSPS governing methane emissions from the oil and natural gas industry as well as proposed source determination standards for determining when oil and natural gas sources should be aggregated for CAA permitting and compliance purposes. The proposed NSPS for methane would extend the 2012 NSPS to remaining equipment and processes not currently regulated under the existing standards, including completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressor station compressors. We continue to evaluate the effect these proposed rules would have on our business and operations. On January 22, 2016, the Department of the Interior proposed rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The proposed rules would, among other things, limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair. The proposed rules are still in the period for public comment. These rules could increase our operating costs and have a material adverse effect on our business and operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. In addition, ongoing international discussions are exploring options to succeed the Kyoto Protocol, most recently at the United Nations Conference on climate change in Paris in November-December 2015. These discussions could result in a legally binding international agreement to make certain global emissions reductions at a national level, which in turn could further drive regulation in the United States. Any future international agreements, federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.

The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, reporting of greenhouse gas emissions from onshore oil and natural gas production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.

Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2015, we owned and operated nine underground injection wells and owned but did not operate two underground injection wells through a less-than-wholly-owned subsidiary, and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or

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operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows.

In addition, some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. At the state level, Texas, New Mexico and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few state and local governments or regional authorities have imposed temporary moratoria on drilling permits. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing within city limits. These actions are the subject of legal challenges. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations.

The EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, in June 2015, the EPA issued draft results of its study on the effects of hydraulic fracturing on drinking water resources. The EPA did not find evidence of widespread, systemic impacts on drinking water resources in the United States, although it did note a lack of data in many areas. Further, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules have been temporarily stayed by the federal district court for the District of Wyoming pending litigation. The EPA has also announced an Advance Notice of Proposed Rulemaking under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals.

Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas,

have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

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The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.

Office Lease

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding our office lease. Such information is incorporated herein by reference.

Employees

At December 31, 2015, we had 151 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.

Available Information

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary

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at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.

Item 1A. Risk Factors.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our Success Is Dependent on the Prices of Oil and Natural Gas. Continued Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2015, the average price of oil was $48.79 per Bbl, ranging from a high of $61.43 per Bbl in mid-June to a low of $34.73 per Bbl in late December based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $2.63 per MMBtu, ranging from a high of $3.23 per MMBtu in mid-January to a low of $1.76 per MMBtu in mid-December based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Throughout 2015, oil and natural gas prices continued to decline sharply from their most recent highs in 2014. Oil prices have decreased 68% from $107.26 per Bbl in mid-June 2014 to $34.73 per Bbl in late December 2015, and natural gas prices have decreased 71% from $6.15 per MMBtu in mid-February 2014 to $1.76 per MMBtu in mid-December 2015. These sharp declines in oil and natural gas prices impacted our revenues, profitability and cash flows in 2015, as compared to 2014, and further declines in the prices of oil or natural gas could have an adverse impact on our borrowing capacity, ability to obtain additional capital, revenues, profitability and cash flows.

Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines caused us to recognize full-cost ceiling impairments in each quarter of 2015, and continued low prices may cause us to recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.”

The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following:


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


•	the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;


•	the prices and availability of competitors’ supplies of oil and natural gas;


•	the price and quantity of foreign imports;


•	the impact of U.S. dollar exchange rates on oil and natural gas prices;


•	domestic and foreign governmental regulations and taxes;


•	speculative trading of oil and natural gas futures contracts;


•	the availability, proximity and capacity of gathering, processing and transportation systems for natural gas;


•	the availability of refining capacity;


•	the prices and availability of alternative fuel sources;


•	weather conditions and natural disasters;


•	political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia;


•	the continued threat of terrorism and the impact of military action and civil unrest;

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•	public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;


•	the level of global oil and natural gas inventories and exploration and production activity;


•	the impact of energy conservation efforts;


•	technological advances affecting energy consumption; and


•	overall worldwide economic conditions.

These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain at economically unattractive levels for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. For example, if oil prices drop and remain below $30.00 per Bbl, we have the flexibility to reduce the number of rigs we are operating from three rigs to two rigs, either for a short time or for the remainder of 2016, beginning as early as the second quarter of 2016. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

We may sell additional equity securities or issue additional debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities.

Our cash flows from operations and access to capital are subject to a number of variables, including:


•	our estimated 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;


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


•	our ability to acquire, locate and produce new reserves;


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


•	our ability to access the equity and debt capital markets.

In addition, the possible occurrence of future events, such as further decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to

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the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

If our revenues continue to decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund acquisitions, increase our rate of growth, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of midstream or other assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following:


•	general economic and industry conditions, including the prices received for oil and natural gas;


•	shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;


•	potential drainage by operators on adjacent properties;


•	loss of or damage to oilfield development and service tools;


•	accidents, equipment failures or mechanical problems;


•	problems with title to the underlying properties;


•	increases in severance taxes;


•	adverse weather conditions that delay drilling activities or cause producing wells to be shut in;


•	domestic and foreign governmental regulations; and


•	proximity to and capacity of gathering, processing and transportation facilities.

Furthermore, our operations involve using some of the latest drilling and completion techniques developed by us and our service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following:


•	landing our wellbore in the desired drilling zone;


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


•	running our casing the entire length of the wellbore;


•	fracture stimulating the planned number of stages; and

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•	being able to run tools and other equipment consistently through the horizontal wellbore.

If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.

The Borrowing Base under Our Credit Agreement is Subject to Periodic Redetermination.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to factors beyond our control. As of February 25, 2016, our borrowing base was $375.0 million, and we had no outstanding borrowings and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2015, the PV-10 of our proved oil and natural gas reserves was $541.6 million, as compared to $1.04 billion at December 31, 2014. We could be required to repay a portion of our bank debt to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.

The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions.

Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to:


•	incur or guarantee additional debt or issue certain types of preferred stock;


•	pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;


•	transfer or sell assets;


•	make certain investments;


•	create certain liens;


•	enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us;


•	consolidate, merge or transfer all or substantially all of our assets;


•	engage in transactions with affiliates; and


•	create unrestricted subsidiaries.

A breach of any of these covenants could result in an event of default under our Credit Agreement and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. Continued low oil and natural gas prices or any further decline in the prices of oil or natural gas may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our

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ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations.

We May Incur Additional Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs.

At February 25, 2016, we had available borrowings of approximately $374.4 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments.

In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement) we may incur significant amounts of additional indebtedness, including under our Credit Agreement or through the issuance of additional notes, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.

A high level of indebtedness could affect our operations in several ways, including the following:


•	requiring a significant portion of our cash flows to be used for servicing our indebtedness;


•	increasing our vulnerability to general adverse economic and industry conditions;


•	placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing;


•	restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and


•	increasing the risk that we may default on our debt obligations.

Our Credit Rating May be Downgraded Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations.

As of February 25, 2016, our corporate credit rating from Standard & Poor’s Rating Services was “B” and our corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Similar to many of our competitors and other companies in the energy industry, in January 2016, our credit rating was placed under review by Moody’s Investors Service due to the possible effects of continued depressed oil and natural gas prices. Any future downgrade could increase the cost of any indebtedness incurred in the future.

Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected.

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Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:


•	natural disasters;


•	adverse weather conditions;


•	loss of drilling fluid circulation;


•	blowouts where oil or natural gas flows uncontrolled at a wellhead;


•	cratering or collapse of the formation;


•	pipe or cement leaks, failures or casing collapses;


•	fires or explosions;


•	releases of hazardous substances or other waste materials that cause environmental damage;


•	pressures or irregularities in formations; and


•	equipment failures or accidents.

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, 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. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana and East Texas. For the year ended December 31, 2015, approximately 26% of our total oil and natural gas production, including approximately 38% of our average daily oil production, was attributable to our properties in the Delaware Basin and approximately 41% of our total oil and natural gas production, including approximately 62% of our average daily oil production, was attributable to our properties in the Eagle Ford shale. At December 31, 2015, approximately 58% of the PV-10 of our total proved oil and natural gas reserves and approximately 69% of our total proved oil reserves were attributable to our properties in the Delaware Basin, and approximately 32% of the PV-10 of our total proved oil and natural gas reserves and approximately 31% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale. We expect that almost all of our operations in 2016 will be in the Delaware Basin.

The industry focus on the Delaware Basin and the Eagle Ford shale may adversely impact our ability to transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. In connection with the sale of the Loving County System, in October 2015, we entered into a 15-year fixed-fee natural gas gathering and processing

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agreement covering the anticipated natural gas production from a significant portion of our acreage in the Delaware Basin in West Texas. In addition, we have a firm natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, which expires in September 2017. However, due to the concentration of our operations we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance.

Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, during the fourth quarters of 2014 and 2015, the Delaware Basin experienced severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In the third quarter