Matador Resources Co - FORM 10-K

Matador Resources Co - FORM 10-K - March 1, 2017

Attached files

Attached files

file	filename
EX-99.1 - EXHIBIT 99.1 - Matador Resources Co	mtdr10-k12312016ex991.htm
EX-32.2 - EXHIBIT 32.2 - Matador Resources Co	mtdr10-k12312016ex322.htm
EX-32.1 - EXHIBIT 32.1 - Matador Resources Co	mtdr10-k12312016ex321.htm
EX-31.2 - EXHIBIT 31.2 - Matador Resources Co	mtdr10-k12312016ex312.htm
EX-31.1 - EXHIBIT 31.1 - Matador Resources Co	mtdr10-k12312016ex311.htm
EX-23.2 - EXHIBIT 23.2 - Matador Resources Co	mtdr10-k12312016ex232.htm
EX-23.1 - EXHIBIT 23.1 - Matador Resources Co	mtdr10-k12312016ex231.htm
EX-21.1 - EXHIBIT 21.1 - Matador Resources Co	mtdr10-k12312016ex211.htm
EX-10.64 - EXHIBIT 10.64 - Matador Resources Co	mtdr10-k12312016ex1064.htm
EX-10.63 - EXHIBIT 10.63 - Matador Resources Co	mtdr10-k12312016ex1063.htm
EX-10.62 - EXHIBIT 10.62 - Matador Resources Co	mtdr10-k12312016ex1062.htm

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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, 2016



¨	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 $1,625,286,901.

As of February 24, 2017, there were 100,034,559 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 2017 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, 2016

TABLE OF CONTENTS




		Page
PART I
ITEM 1.	BUSINESS	2
ITEM 1A.	RISK FACTORS	28
ITEM 1B.	UNRESOLVED STAFF COMMENTS	49
ITEM 2.	PROPERTIES	49
ITEM 3.	LEGAL PROCEEDINGS	49
ITEM 4.	MINE SAFETY DISCLOSURES	50

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	51
ITEM 6.	SELECTED FINANCIAL DATA	54
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	56
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	76
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	77
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	77
ITEM 9A.	CONTROLS AND PROCEDURES	77
ITEM 9B.	OTHER INFORMATION	80

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	80
ITEM 11.	EXECUTIVE COMPENSATION	80
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	80
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	80
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	80

PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	81

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (this “Annual Report”) 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, although not all forward-looking statements contain such identifying 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, the sufficiency of our 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 our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions 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 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 with our business;


•	our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;


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


•	general economic conditions;


•	competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;


•	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 that are not historical.

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

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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 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, 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, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.

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. Additionally, we conduct midstream operations primarily, as of February 17, 2017, through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

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, divestitures and joint ventures.

Despite a challenging commodity price environment in 2016, 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. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important financing transactions in 2016, including two equity offerings, an issuance of senior unsecured notes and an increase in the borrowing base under our Credit Agreement (as defined below). These transactions, as well as the formation of the Joint Venture in February 2017, increased our operational flexibility and further strengthened our balance sheet.

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2016 Highlights

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2016, we achieved record oil, natural gas and average daily oil equivalent production. In 2016, we produced 5.1 million Bbl of oil, an increase of 13%, as compared to 4.5 million Bbl of oil produced in 2015. We also produced 30.5 Bcf of natural gas, an increase of 10% from 27.7 Bcf of natural gas produced in 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12%, as compared to 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for the year ended December 31, 2015. The increase in oil and natural gas production was primarily a result of our ongoing delineation and development operations in the Delaware Basin throughout 2016, which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Oil production comprised 50% 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, 2016, as compared to 49% for the year ended December 31, 2015.

Increased Oil and Oil Equivalent Reserves

At December 31, 2016, our estimated total proved oil and natural gas reserves were 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, an increase of 24% from December 31, 2015. The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 9% and 7% to $575.0 million and $581.5 million, respectively, at December 31, 2016, from $529.2 million and $541.6 million, respectively, at December 31, 2015, primarily as a result of our ongoing delineation and development operations in the Delaware Basin. 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 25% to 57.0 million Bbl at December 31, 2016 from 45.6 million Bbl at December 31, 2015. Our proved natural gas reserves increased 24% to 292.6 Bcf at December 31, 2016 from 236.9 Bcf at December 31, 2015. This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development operations in the Delaware Basin during 2016.

At December 31, 2016, proved developed reserves included 22.6 million Bbl of oil and 126.8 Bcf of natural gas, and proved undeveloped reserves included 34.4 million Bbl of oil and 165.9 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 41% and 54%, respectively, of our total proved oil and natural gas reserves at December 31, 2016. Proved developed reserves and proved oil reserves comprised 40% and 54%, respectively, of our total proved oil and natural gas reserves at December 31, 2015.

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 better 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 three years, as we continue to apply what we learned from our Eagle Ford shale and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2017.

We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin in 2016, including 40 gross (35.6 net) operated and 15 gross (1.4 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2016. As a result, at December 31, 2016, our total acreage position in the Delaware Basin had increased to approximately 163,700 gross (94,300 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 asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Ranger and Twin Lakes asset 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 increased approximately 145% (2.5-fold) to 15,941 BOE per day (57% of total oil equivalent production), including 10,395 Bbl of oil per day (75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total natural gas production), in 2016, as compared to 6,518 BOE per day (26% of total oil equivalent production), including 4,648 Bbl of oil per day (38% of total oil production) and 11.2 MMcf of natural gas per day (15% of total natural gas production), in 2015. We expect our Delaware Basin production to increase throughout 2017 as we continue the delineation and development of these asset areas.

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Operational highlights in the Delaware Basin (as further described below in “—Principal Areas of Interest — Exploration and Production Segment—Southeast New Mexico and West Texas — Delaware Basin” and “—Midstream Segment”) in 2016 included:


•	our continued improvement in operational efficiencies throughout the Delaware Basin, particularly in our Rustler Breaks and Wolf asset areas, as we achieved improvements in both drilling times and well costs;


•	in our Rustler Breaks asset area, the continued delineation and development of previously tested horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—and the successful testing of a new, deeper bench of the Wolfcamp B interval, which is sometimes referred to as the Blair Shale;


•	in our Wolf asset area, continued development of the Wolfcamp A-XY interval as well as the significant improvement in well results in the Second Bone Spring, as compared to our initial tests in that interval;


•	in our Ranger asset area, the initial results from three wells completed in the Third Bone Spring formation on our Mallon leasehold, which tested at the highest 24-hour initial potential flow rates of any wells we have drilled to date in the Delaware Basin and which illustrate the potential of our northern Delaware Basin acreage position;


•	a positive test of the Strawn formation in our Twin Lakes asset area from the Olivine State 5-16S-37E TL #1, a vertical well; and

•

the significant progress made with our midstream operations including the start-up of our Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) and associated natural gas gathering system in our Rustler Breaks asset area, our initial salt water disposal well and facility and associated water gathering lines in our Rustler Breaks asset area and two additional salt water disposal wells and facilities in our Wolf asset area.

We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or in Northwest Louisiana and East Texas during 2016, although we did participate in the drilling and completion of 2 gross (less than 0.1 net) non-operated Eagle Ford shale wells and 15 gross (2.1 net) non-operated Haynesville shale wells that began producing in 2016.

Financing Arrangements

On March 11, 2016, we completed a public offering of 7,500,000 shares of our common stock. After deducting offering costs totaling approximately $0.8 million, we received net proceeds of approximately $141.5 million. In late October 2016, the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2016, increased our borrowing base from $300.0 million to $400.0 million. On December 9, 2016, we issued $175.0 million of our 6.875% senior unsecured notes due 2023 (the “Additional Notes”) in a private placement. We received net proceeds from the issuance of Additional Notes of $181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. Also on December 9, 2016, we completed a public offering of 6,000,000 shares of our common stock. After deducting offering costs totaling approximately $0.4 million, we received net proceeds of approximately $145.8 million. See Notes 6 and 10 to the consolidated financial statements in this Annual Report for more details on each of the above items.

2017 Recent Developments

Between January 1, 2017 and February 22, 2017, we acquired approximately 13,900 gross (8,200 net) leasehold and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around our existing acreage in the Delaware Basin. Some of this acreage, and a portion of the production, included properties identified at the time of our December 2016 equity and notes offerings. These transactions were pending at the time of those offerings and closed subsequent to December 31, 2016, bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately $111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production.

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Midstream Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas.

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Principal Areas of Interest — Exploration and Production Segment

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 and East Texas. During 2016, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. 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 asset areas by exploring for more conventional targets as well, although at December 31, 2016, essentially all of our efforts were focused on unconventional plays.

At December 31, 2016, 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, 2016.



			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⁾	163,703	94,312	312	135.1	4,162	1,660.2	79,388	35.5	15,941
South Texas:
Eagle Ford ⁽⁵⁾	30,669	27,777	136	115.1	249	214.2	13,298	55.0	4,952
Northwest Louisiana/East Texas:
Haynesville	20,105	12,452	204	19.8	431	103.0	12,414	61.1	6,517
Cotton Valley ⁽⁶⁾	21,614	19,071	81	54.2	71	50.1	652	100.0	403
Area Total ⁽⁷⁾	26,062	23,278	285	74.0	502	153.1	13,066	63.0	6,920
Total ⁽⁸⁾	220,434	145,367	733	324.2	4,913	2,027.5	105,752	41.4	27,813

__________________

(1)

Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2016. 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, 2016, these engineered drilling locations included only 163 gross (90.3 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Delaware and Strawn formations in the Delaware Basin, 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 12 gross (4.0 net) locations to which we have assigned proved undeveloped reserves in the Haynesville.

(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 Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, 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, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2016.


(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.


(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.


(8)	During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.

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, 2016, 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, 2016, we also were the operator for approximately 93% of our Eagle Ford acreage and

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approximately 65% of our Haynesville acreage, including approximately 32% 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 formation 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 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 the source rocks for oil and natural gas produced in the basin. Historically, production has come from 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.

As noted above in “—2016 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2016, and as a result, at December 31, 2016, our total acreage position in Southeast New Mexico and West Texas was approximately 163,700 gross (94,300 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,700 gross (20,400 net) acres in our Ranger asset area in Lea County, 48,000 gross (17,000 net) acres in our Arrowhead asset area in Eddy County, 25,100 gross (16,500 net) acres in our Rustler Breaks asset area in Eddy County, 13,500 gross (8,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 42,900 gross (30,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2016. 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, 2016, our acreage position in the Delaware Basin was approximately 36% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical Strawn well, our acreage position in the Delaware Basin was approximately 47% held by existing production at December 31, 2016.

During the year ended December 31, 2016, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin, including 40 gross (35.6 net) operated wells and 15 gross (1.4 net) non-operated wells, throughout our various asset areas. At December 31, 2016, we had tested a number of different producing horizons at various locations across our acreage position, 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, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2016. Our average daily oil equivalent production from the Delaware Basin increased approximately 145% (2.5-fold) to 15,941 BOE per day (57% of total oil equivalent production), including 10,395 Bbl of oil per day (75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total natural gas production), in 2016, as compared to 6,518 BOE per day (26% of total oil equivalent production), including 4,648 Bbl of oil per day (38% of total oil production) and 11.2

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MMcf of natural gas per day (15% of total natural gas production), in 2015. In addition, our average daily oil equivalent production from the Delaware Basin also grew approximately 138% (2.4-fold) from 8,720 BOE per day in the fourth quarter of 2015 to 20,670 BOE per day in the fourth quarter of 2016.

At December 31, 2016, approximately 75% of our estimated total proved oil and natural gas reserves, or 79.4 million BOE, was attributable to the Delaware Basin, including approximately 46.9 million Bbl of oil and 195.1 Bcf of natural gas, a 68% increase, as compared to 47.1 million BOE for the year ended December 31, 2015. Our Delaware Basin proved reserves at December 31, 2016 comprised approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves, as compared to approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves at December 31, 2015.

At December 31, 2016, we had identified 4,162 gross (1,660.2 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 and the deeper Strawn formation. These locations include 2,546 gross (1,478.1 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, 2016 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our upcoming horizontal test of the Wolfcamp D in 2017). 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, 2016, these potential future drilling locations included only 163 gross (90.3 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Delaware and Strawn formations, to which we have assigned proved undeveloped reserves.

At December 31, 2016 and February 22, 2017, we were operating four drilling rigs in the Delaware Basin—two in the Rustler Breaks asset area, one in the Wolf/Jackson Trust asset areas and one in the Ranger/Arrowhead and Twin Lakes asset areas. We intend to operate four rigs in these asset areas throughout the remainder of 2017, and we expect to add a fifth drilling rig in the Delaware Basin beginning early in the second quarter of 2017. Thereafter, we expect to operate this fifth drilling rig in the Rustler Breaks asset area throughout the remainder of 2017. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated substantially all of our 2017 estimated capital expenditure budget to our drilling and completion program and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities.

Rustler Breaks Asset Area

We made significant progress delineating, developing and testing our acreage position in the Rustler Breaks asset area in 2016. The ten Wolfcamp A-XY wells and two Wolfcamp B (Middle) wells completed and placed on production in the Rustler Breaks asset area in 2016 were consistent with or better than the best Wolfcamp A-XY wells and Wolfcamp B (Middle) wells drilled by us in this asset area to date. The Paul 25-24S-28E RB #221H well tested at the highest 24-hour initial potential flow rate of any Wolfcamp A-XY well we have drilled at Rustler Breaks—1,701 BOE per day (74% oil)—and early performance from this well indicates that it may be the best Wolfcamp A-XY well drilled to date at Rustler Breaks. During 2016, we tested our first five wells drilled in the deepest bench of the Wolfcamp B (Blair) at Rustler Breaks. This is the third bench of the Wolfcamp B we have successfully tested at Rustler Breaks. These three target benches of the Wolfcamp B occur starting approximately 300 feet into the 1,000-foot thick Wolfcamp B interval at Rustler Breaks and are each about 200 to 250 feet apart vertically.

The 24-hour initial potential flow rates from the five Wolfcamp B (Blair) wells we completed and placed on production in 2016—the Dr. Scrivner Federal 01-24S-28E RB #228H, the Jimmy Kone 05-24S-28E RB #228H, the Janie Conner 13-24S-28E RB #221H, the Anne Com 15-24S-28E RB #221H (Anne Com #221H) and the Tiger 14-24S-28E RB #227H—were the five highest 24-hour test results we have reported in the Delaware Basin to date (with the exception of the three Mallon wells discussed below) at 2,570 BOE per day, 2,438 BOE per day, 2,384 BOE per day, 2,364 BOE per day and 1,812 BOE per day, respectively, at about 35% oil. These 24-hour initial potential test results compare favorably to those from other wells completed in the Wolfcamp B (Middle), the Tiger 14-24S-28E RB #224H and Janie Conner 13-24S-28E RB #224H wells, which had 24-hour initial potential rates of 1,533 BOE per day (43% oil) and 1,703 BOE per day (59% oil), respectively. The initial oil volumes from these lower Wolfcamp B (Blair) completions were reasonably comparable to or better than those in the Wolfcamp B (Middle), while the initial natural gas volumes were higher. In some instances, the oil rates tested on the lower Wolfcamp B (Blair) wells were close to those tested on the Wolfcamp A-XY wells.

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In the Rustler Breaks asset area in 2016, we reduced our average drilling time from spud to total depth in the Wolfcamp A-XY by approximately 31% and 16%, as compared to 2014 and 2015, respectively, and in the Wolfcamp B by approximately 50% and 35%, respectively. Our fastest-drilled Wolfcamp A-XY well, the B. Banker 33-23S-28E #226H well, was drilled in 12.5 days from spud to a total depth of 14,350 feet, a decrease of almost 50% from the average drilling time in late 2014, and our fastest-drilled Wolfcamp B well, the Anne Com #221H, was drilled in 17.4 days from spud to a total depth of 15,364 feet, a decrease of 58% from the average drilling time in 2014. These drilling times of 12.5 and 17.4 days were faster than our 2016 drilling objectives of 14 days for the Wolfcamp A-XY and 18 days for the Wolfcamp B, respectively, from spud to total depth. We delivered faster drilling times as a result of our increased knowledge of the geology and our experience with drilling in the Rustler Breaks asset area, as well as improvements in drilling the curve between the vertical and horizontal portions of these wells and continued applications of improved drill bit and bottomhole assembly technologies.

Due in part to these improvements in drilling times, continued innovation by our technical staff and lower oilfield services costs, the costs associated with recent Wolfcamp A-XY and Wolfcamp B wells at Rustler Breaks continued to decline throughout 2016. We were able to drill, complete and equip several wells in the Wolfcamp A-XY for just under $5 million each and in the Wolfcamp B for approximately $5.7 million each in mid-to-late 2016.

All of the Wolfcamp A-XY wells completed and placed on production in the Rustler Breaks asset area in 2016 were stimulated using our Generation 3 Wolfcamp stimulation treatment design, consisting of approximately 40 Bbl of fracturing fluid and 3,000 pounds of primarily 30/50 white sand per completed lateral foot. Similarly, we pumped this Generation 3 Wolfcamp stimulation treatment design in our Wolfcamp B (Blair) completions in the third and fourth quarters of 2016. Prior to this, most of our Wolfcamp A and B completions in the Rustler Breaks asset area used approximately 30 to 40 Bbl of fracturing fluid and 2,000 pounds of primarily 30/50 white sand per completed lateral foot. We also continued to pump diverting agents in most of our stimulation treatments in the Rustler Breaks asset area during the third and fourth quarters of 2016.

Wolf and Jackson Trust Asset Areas

Operational efficiencies continued to improve in the Wolf asset area as well. In 2016, we reduced our average drilling time from spud to total depth in the Wolfcamp A-X and A-Y by approximately 52% and 10% as compared to 2014 and 2015, respectively, and in the Second Bone Spring by approximately 42% as compared to our first well drilled in the Second Bone Spring in 2015. Our fastest-drilled Wolfcamp A well, the Dorothy White 82-TTT-B33 #203H well, was drilled in 17.3 days from spud to a total depth of 15,550 feet, a decrease of 61% from the 2014 average drilling time and faster than our 2016 Wolfcamp A drilling objective of 18 days from spud to total depth in the Wolf asset area. The Barnett 90-TTT-B01 WF #124H (Barnett #124H) well, a Second Bone Spring test, was drilled in approximately 11.5 days (11.2 days normalized to a 5,000-foot lateral length) from spud to total depth, with drilling times being faster than our 2016 year-end drilling target of 13 days for Second Bone Spring wells. In the Barnett #124H and subsequent Second Bone Spring wells drilled in 2016, our drilling engineers were also able to eliminate a second intermediate casing string typically used when drilling the Second Bone Spring in this area. Not only did eliminating this casing string save approximately $650,000 in well costs on each Second Bone Spring well drilled in 2016, but it also provided for larger casing to be set through the lateral, thereby reducing hydraulic horsepower costs during fracturing operations and enhancing the number of artificial lift options available in the future. Total costs to drill, complete and equip Second Bone Spring wells in the Wolf asset area were just over $4 million in mid-to-late 2016.

Well costs associated with recent Wolfcamp A-X and A-Y wells drilled and completed in the Wolf asset area also continued to decline. Costs to drill, complete and equip Wolfcamp A wells ranged between $5 and $6 million, with a number of these wells at or below $5.5 million in mid-to-late 2016. As in the Rustler Breaks asset area, we attribute these cost savings to the innovation and use of new technologies by our drilling, completions and production teams, as well as lower oilfield services costs.

Our Second Bone Spring completions in 2016 represented significant improvements over our initial Second Bone Spring well drilled in the Wolf asset area in 2015. We attribute this improvement in well performance to the increased stimulation treatments pumped in 2016. The 2016 wells were completed using approximately 40 Bbl of fracturing fluid and 2,000 pounds of primarily 20/40 sand per completed lateral foot, compared to our initial Second Bone Spring completion in the Wolf asset area, which used only 20 Bbl of fracturing fluid and about 1,300 pounds of primarily 30/50 sand per completed lateral foot. In particular, we were pleased with the test results observed from the Johnson 44-02S-B53 WF #121H well, which had the highest test rate achieved from any Second Bone Spring well we have drilled to date of 1,167 BOE per day (58% oil).

We did not complete and place on production any new wells in our Jackson Trust asset area in 2016, although we do have several wells planned in our Jackson Trust asset area for 2017.

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Ranger and Arrowhead Asset Areas

In the Ranger asset area in Lea County, New Mexico, we completed and placed on production the Mallon 27 Federal Com #1H, #2H and #3H wells, each of which are 7,300-foot laterals drilled and completed in the Third Bone Spring sand. These wells were the first operated wells we have drilled on the acreage acquired in our 2015 merger with Harvey E. Yates Company (“HEYCO” and, such merger, the “HEYCO Merger”). In aggregate, these three wells flowed 7,856 BOE per day (91% oil) in their 24-hour initial potential tests. Each well was completed with a 29-stage fracture treatment, including approximately 40 Bbl of fluid and 3,000 pounds of primarily 20/40 white sand per completed lateral foot. At December 31, 2016, these were the largest fracture treatments we have pumped in a Bone Spring completion. The Mallon wells were among the best wells we have drilled to date in the Delaware Basin, and these wells illustrate the potential of our northern Delaware Basin acreage position.

We did not conduct any operated drilling and completion activities in our Arrowhead asset area during 2016, although we did participate in one new, non-operated well on our Arrowhead acreage during the first quarter of 2016. This well, the Yates Petroleum Corporation Baroque “BTQ” Federal Com #1H well, tested at flow rates averaging approximately 1,300 BOE per day (including approximately 1,100 Bbl of oil per day and 1.2 MMcf of natural gas per day) beginning in late March 2016. This well is located in the eastern portion of our Arrowhead asset area in Eddy County, New Mexico. We own a 9.5% working interest in this well, which provides yet another indication of the prospectivity of our northern Delaware Basin acreage.

Twin Lakes Asset Area

In our Twin Lakes asset area in northern Lea County, New Mexico, we drilled an initial data collection well, the Olivine State 5-16S-37E TL #1 (Olivine State #1), during the fourth quarter of 2015. This was a vertical pilot hole drilled for the purpose of collecting whole core and a detailed suite of geophysical logs to assist us in determining the landing target for our initial horizontal test of the Wolfcamp D interval at Twin Lakes. We collected about 400 feet of whole core throughout much of the Wolfcamp D interval, and our geoscience staff, along with third-party vendors, have conducted detailed description and analysis of the core data and well logs. The Olivine State #1 was drilled through the Wolfcamp D and into and through the Strawn formation below. The Strawn interval at about 11,500 feet is a complex carbonate formation that has previously produced significant quantities of oil and natural gas in the Twin Lakes area. Upon drilling through the Strawn interval, our geoscience staff analyzed the well logs taken across the interval and determined that there was the potential for a Strawn test. As a result, the Olivine State #1 was perforated and completed in the Strawn interval with a small acid treatment during the first quarter of 2016. This well flowed 691 BOE per day (84% oil) during a 24-hour initial potential test, consisting of 579 Bbl of oil per day and 0.7 MMcf of natural gas per day, at a flowing surface pressure of 350 psi on a 32/64 inch choke. Given the positive results from this Strawn test, we elected to produce the Olivine State #1 rather than plug back, kick off and drill a horizontal Wolfcamp D test from this vertical wellbore as originally anticipated. We expect to drill a new horizontal well to test the Wolfcamp D interval beginning late in the first quarter of 2017.

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, 2016, our properties included approximately 30,700 gross (27,800 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. Approximately 85% of our Eagle Ford acreage was held by production at December 31, 2016, and approximately 95% of our Eagle Ford acreage was either held by production at December 31, 2016 or not burdened by lease expirations before 2018.

We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2016, although we did participate in the drilling and completion of two gross (less than 0.1 net) non-operated Eagle Ford shale wells that were turned to sales in 2016. In fact, as of December 31, 2016, we had not drilled any operated wells in the Eagle Ford shale since early 2015, when we completed and placed on production 17 gross (17.0 net) operated Eagle Ford shale wells in the first four months of 2015. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 52% to 4,952 BOE per day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016, as compared 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, 2016, 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2015, approximately 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale.

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At December 31, 2016, approximately 13% of our estimated total proved oil and natural gas reserves, or 13.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.1 million Bbl of oil and 19.3 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016, as compared to approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves at December 31, 2015.

At December 31, 2016, we had identified 249 gross (214.2 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 that any Eagle Ford wells 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. Approximately 95% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2018 at December 31, 2016. At December 31, 2016, these 249 gross (214.2 net) identified drilling locations included only 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves.

These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and Edwards 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, 2016, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations.

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 2016, although we did participate in the drilling and completion of 15 gross (2.1 net) non-operated Haynesville shale wells that were turned to sales in 2016. These wells included nine gross (1.9 net) Haynesville wells operated by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove acreage in southern Caddo Parish, Louisiana. These nine wells came on production at an average of 13.5 MMcf per day and were drilled and completed for an average of under $7 million. We do not plan to drill any operated Haynesville shale wells in 2017.

At December 31, 2016, we held approximately 26,100 gross (23,300 net) acres in Northwest Louisiana and East Texas, including 20,100 gross (12,500 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 32% of the 13,200 gross (6,400 net) acres that we consider to be in the core area of the Haynesville play.

For the year ended December 31, 2016, approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day, including 12 Bbl of oil per day and 41.4 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 50% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2016, as compared to approximately 64% of our daily natural gas production and approximately 0.1% of our daily oil production during 2015. During 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 properties in Northwest Louisiana and East Texas.

For the year ended December 31, 2016, approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3%, or 2.3 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. 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. At December 31, 2016, approximately 12% of our estimated total proved reserves, or 12.4 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage.

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At December 31, 2016, we had identified and engineered 431 gross (103.0 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 431 gross (103.0 net) locations identified for future drilling on our Haynesville acreage, 357 gross (50.1 net) locations have been identified within the 13,200 gross (6,400 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, 2016, these potential future drilling locations included only 12 gross (4.0 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.

At December 31, 2016, we had approximately 20,100 gross (12,500 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 13,200 gross (6,400 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, 2016.

Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,100 net acres. We have identified 25 gross (19.6 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 just over 31%.

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, 2016, 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 2016 and do not plan to drill any of these locations in 2017. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale

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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 asset areas in Northwest Louisiana and East Texas. At December 31, 2016, we held an estimated 11,600 gross (9,200 net) leasehold and mineral acres by existing production in these areas.

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

During the year ended December 31, 2016, we released all of our leasehold interests in Southwest Wyoming and adjacent areas in Utah and Idaho, which were originally leased as a part of a natural gas shale exploration prospect targeting the Meade Peak shale. As a result, we held no leasehold interests in these areas at December 31, 2016.

Midstream Segment

The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. Through the ownership and operation of these facilities, we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the value received for our production. With the exception of a joint venture, which we controlled and which owned salt water disposal assets in Loving County, Texas, all of our midstream operations were wholly-owned by the Company at December 31, 2016. In February 2017, we contributed our Delaware Midstream Assets to San Mateo.

Southeast New Mexico and West Texas — Delaware Basin

In late August 2016, we successfully completed and began operating the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico. The Black River Processing Plant has an inlet capacity of approximately 60 MMcf of natural gas per day, which is almost twice the size of the previous cryogenic processing plant we built in our Wolf asset area in Loving County, Texas (the “Wolf Processing Plant”) and subsequently sold to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Black River Processing Plant and associated gathering system was built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with priority one takeaway and processing services for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and processing of third-party natural gas. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition, in late December 2016, we placed in service our initial salt water disposal well and associated salt water disposal facility and water gathering pipelines in our Rustler Breaks asset area. We disposed of over 800,000 Bbl of salt water during the well’s first two months of operation.

In our Wolf asset area in Loving County, Texas, we have oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production and a small volume of third-party natural gas. We retained this three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to EnLink in October 2015. The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. We also retained our interest in commercial salt water disposal assets in Loving County. During 2016, we disposed of approximately 10.2 million Bbl of salt water, including disposal of third-party salt water on a commercial basis. At February 22, 2017, San Mateo had capacity to dispose of approximately 50,000 Bbl of salt water per day in the Wolf asset area. San Mateo is in the process of completing its third salt water disposal well and related disposal facility in the Wolf asset area, which is expected to be operational by the end of the first quarter of 2017 and which should increase the total salt water disposal capacity in the Wolf asset area to approximately 75,000 Bbl per day.

South Texas / Northwest Louisiana and East Texas

In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases there and from third parties. We also have four non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo.

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Operating Summary

The following table sets forth certain unaudited production and operating data for the years ended December 31, 2016, 2015 and 2014.



	Year Ended December 31,
	2016		2015			2014
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl)	5,096		4,492			3,320
Natural gas (Bcf)	30.5		27.7			15.3
Total oil equivalent (MBOE) ⁽¹⁾	10,180		9,109			5,870
Average daily production (BOE/d) ⁽¹⁾	27,813		24,955			16,082
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	41.19	$	45.27		$	87.37
Oil, with realized derivatives (per Bbl)	$	42.34	$	59.13		$	88.94
Natural gas, without realized derivatives (per Mcf)	$	2.66	$	2.71		$	5.08
Natural gas, with realized derivatives (per Mcf)	$	2.78	$	3.24		$	5.06
Operating Expenses (per BOE):
Production taxes, transportation and processing	$	4.23	$	3.91	(2)	$	5.65
Lease operating	$	5.52	$	6.01	(3)	$	8.51	(3)
Plant and other midstream services operating	$	0.53	$	0.38		$	0.24
Depletion, depreciation and amortization	$	11.99	$	19.63		$	22.95
General and administrative	$	5.41	$	5.50		$	5.48

__________________


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


(2)	$0.01 per BOE reclassified to third-party midstream services revenues due to our midstream business becoming a reportable segment in the third quarter of 2016.


(3)	$0.38 and $0.24 per BOE reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.

The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 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)	3,805			1,286			—			5			5,096
Natural gas (Bcf)	12.2			3.1			14.3			0.9			30.5
Total oil equivalent (MBOE) ⁽³⁾	5,834			1,813			2,385			148			10,180
Percentage of total annual net production	57.3		%	17.8		%	23.4		%	1.5		%	100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)	10,395			3,517			—			12			13,924
Natural gas (MMcf/d)	33.3			8.6			39.1			2.3			83.3
Total oil equivalent (BOE/d)	15,941			4,952			6,517			403			27,813
Average Sales Prices⁽⁴⁾
Oil (per Bbl)	$	41.76		$	39.49		$	—		$	38.78		$	41.19
Natural gas (per Mcf)	$	3.15		$	3.11		$	2.17		$	2.27		$	2.66
Total oil equivalent (per BOE)	$	33.81		$	33.46		$	13.04		$	14.39		$	28.60
Production Costs ⁽⁵⁾
Lease operating, transportation and processing (per BOE)	$	7.32		$	12.74		$	4.73		$	17.07		$	7.82

__________________


(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.

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(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 plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

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 Prices⁽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, transportation and processing (per BOE) ⁽⁶⁾	$	8.84		$	9.25		$	4.91		$	19.23		$	7.90

_________________


(1)	Includes one 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 plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.


(6)	Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.

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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 Prices⁽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, transportation and processing (per BOE) ⁽⁶⁾	$	13.08		$	10.34		$	8.13		$	17.58		$	10.29

_________________


(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 plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.


(6)	Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.

Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015. This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year ended December 31, 2015. Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015. Our average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015.

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.

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Producing Wells

The following table sets forth information relating to producing wells at December 31, 2016. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 72% in all wells that we operated at December 31, 2016. 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⁾	261	116.0	51	19.1	312	135.1
South Texas:
Eagle Ford⁽²⁾	132	111.1	4	4.0	136	115.1
Northwest Louisiana/East Texas:
Haynesville	—	—	204	19.8	204	19.8
Cotton Valley ⁽³⁾	2	2.0	79	52.2	81	54.2
Area Total	2	2.0	283	72.0	285	74.0
Total	395	229.1	338	95.1	733	324.2

__________________


(1)	Includes 176 gross (50.5 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, 2016, 2015 and 2014. 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 that 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⁾
	2016			2015			2014
Estimated Proved Reserves Data: ⁽²⁾
Estimated proved reserves:
Oil (MBbl)	56,977			45,644			24,184
Natural Gas (Bcf) ⁽³⁾	292.6			236.9			267.1
Total (MBOE) ⁽⁴⁾	105,752			85,127			68,693
Estimated proved developed reserves:
Oil (MBbl)	22,604			17,129			14,053
Natural Gas (Bcf) ⁽³⁾	126.8			101.4			102.8
Total (MBOE) ⁽⁴⁾	43,731			34,037			31,185
Percent developed	41.4		%	40.0		%	45.4		%
Estimated proved undeveloped reserves:
Oil (MBbl)	34,373			28,515			10,131
Natural Gas (Bcf) ⁽³⁾	165.9			135.5			164.3
Total (MBOE)⁽⁴⁾	62,021			51,090			37,508
Standardized Measure ⁽⁵⁾ (in millions)	$	575.0		$	529.2		$	913.3
PV-10 ⁽⁶⁾ (in millions)	$	581.5		$	541.6		$	1,043.4

__________________


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

(2)

Our estimated proved reserves, Standardized Measure and PV-10 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, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, and for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 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)	Primarily 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 in 2015, 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. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016.


(5)	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.

(6)

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, 2016, 2015 and 2014 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, 2016, 2015 and 2014 were, in millions, $6.5, $12.4 and $130.1, respectively.

Our estimated total proved oil and natural gas reserves increased 24% from 85.1 million BOE at December 31, 2015 to 105.8 million BOE at December 31, 2016. We added 42.0 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2016, approximately 4.1 times our 2016 annual production of 10.2 million BOE. Our proved oil reserves grew 25% from approximately 45.6 million Bbl at December 31, 2015 to approximately 57.0 million Bbl at December 31, 2016. Our proved natural gas reserves increased 24% from 236.9 Bcf at December 31, 2015 to 292.6 Bcf at December 31, 2016. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2016. We incurred approximately 11.2 million BOE in net downward revisions to our proved reserves during 2016 as a result of the reclassification of certain proved undeveloped reserves to contingent resources, primarily due to the lower oil and natural gas prices used to estimate proved reserves at December 31, 2016, as compared to December 31, 2015. These contingent resources may be reclassified to proved undeveloped reserves in future periods should the oil and natural gas prices used to estimate proved oil and natural gas reserves improve from the prices at December 31, 2016. Our proved reserves to production ratio at December 31, 2016 was 10.4, an increase of 11% from 9.4 at December 31, 2015.

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The Standardized Measure of our total proved oil and natural gas reserves increased 9% from $529.2 million at December 31, 2015 to $575.0 million at December 31, 2016. The PV-10 of our total proved oil and natural gas reserves increased 7% from $541.6 million at December 31, 2015 to $581.5 million at December 31, 2016. The increase in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2016, which was partially impacted by the lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2016, as compared to December 31, 2015. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2016 were $39.25 per Bbl and $2.48 per MMBtu, a decrease of 17% and 4%, respectively, as compared to average oil and natural gas prices of $46.79 per Bbl and $2.59 per MMBtu used to estimate proved reserves at December 31, 2015. Our total proved reserves were made up of approximately 54% oil and 46% natural gas at December 31, 2016 and December 31, 2015.

Our proved developed oil and natural gas reserves increased 28% from 34.0 million BOE at December 31, 2015 to 43.7 million BOE at December 31, 2016 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 32% from 17.1 million Bbl at December 31, 2015 to 22.6 million Bbl at December 31, 2016. Our proved developed natural gas reserves increased 25% from 101.4 Bcf at December 31, 2015 to 126.8 Bcf at December 31, 2016.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2016.



	Proved Developed Reserves
	Proved Developed Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2015	34,037
Extensions and discoveries	12,583
Revisions of prior estimates	408
Production	(10,180	)
Conversion of proved undeveloped to proved developed	6,883
As of December 31, 2016	43,731

__________________


(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 51.1 million BOE at December 31, 2015 to 62.0 million BOE at December 31, 2016. Our proved undeveloped oil and natural gas reserves increased from 28.5 million Bbl and 135.5 Bcf, respectively, at December 31, 2015 to 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016, primarily as a result of our delineation and development operations in the Delaware Basin.

At December 31, 2016, 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, 2016 within five years of booking these reserves.

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2016.



	Proved Undeveloped Reserves
	Proved Undeveloped Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2015	51,090
Extensions and discoveries	29,408
Revisions of prior estimates	(11,594	)
Conversion of proved undeveloped to proved developed	(6,883	)
As of December 31, 2016	62,021

__________________


(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 2013, 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⁾
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
2016	4,705	13.1	6,883	94,579
Total	14,283	89.5	29,187	$	517,217

__________________


(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, 2016.



	Net Proved Reserves⁽¹⁾
	Oil	Natural Gas	Oil Equivalent	Standardized Measure ⁽²⁾		PV-10 ⁽³⁾
	(MBbl)	(Bcf)	(MBOE) ⁽⁴⁾	(in millions)		(in millions)
Southeast New Mexico/West Texas:
Delaware Basin	46,873	195.1	79,388	$	446.0	$	451.0
South Texas:
Eagle Ford ⁽⁵⁾	10,066	19.3	13,298	85.6		86.6
Northwest Louisiana/East Texas:
Haynesville	—	74.5	12,414	41.5		42.0
Cotton Valley ⁽⁶⁾	38	3.7	652	1.9		1.9
Area Total	38	78.2	13,066	43.4		43.9
Total	56,977	292.6	105,752	$	575.0	$	581.5

__________________


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


(2)	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.

(3)

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, 2016 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, 2016 were approximately $6.5 million.


(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 39 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, 2016.



	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin	79,087	33,699	84,616	60,613	163,703	94,312
South Texas:
Eagle Ford	26,402	23,682	4,267	4,095	30,669	27,777
Northwest Louisiana/East Texas:
Haynesville	16,739	9,088	3,366	3,364	20,105	12,452
Cotton Valley	18,108	16,078	3,506	2,993	21,614	19,071
Area Total ⁽¹⁾	22,030	19,761	4,032	3,517	26,062	23,278
Total ⁽²⁾	127,519	77,142	92,915	68,225	220,434	145,367

__________________


(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.


(2)	During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2016 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 2020 and beyond represents an immaterial amount of our overall undeveloped acreage.

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	Acres		Acres		Acres
	Expiring 2017		Expiring 2018		Expiring 2019
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin ⁽¹⁾	17,604	7,987	39,704	25,294	15,404	9,086
South Texas:
Eagle Ford	1,435	1,375	896	753	204	156
Northwest Louisiana/East Texas:
Haynesville	—	—	—	—	326	324
Cotton Valley	—	—	—	—	—	—
Area Total ⁽²⁾	—	—	—	—	326	324
Total	19,039	9,362	40,600	26,047	15,934	9,566

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(1)

Approximately 54% of the acreage expiring in the next three years is associated with our Twin Lakes asset 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 asset area in 2017 through our 2017 drilling activities or by paying an additional lease bonus, where applicable.


(2)	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 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, 2016, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ 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, 2016, 2015 and 2014.



	Year Ended December 31,
	2016		2015		2014
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	44	23.5	53	26.7	89	39.9
Dry	—	—	—	—	—	—
Exploration Wells
Productive	28	15.6	28	17.5	12	10.6
Dry	—	—	—	—	—	—
Total Wells
Productive	72	39.1	81	44.2	101	50.5
Dry	—	—	—	—	—	—

Marketing and Customers

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.

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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. The prices we receive are based on various pipeline indices less any associated fees. When there is an opportunity to do so, we may have our natural gas processed at our or third parties’ processing facilities to 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 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, directly or indirectly, 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. 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 years ended December 31, 2016, 2015 and 2014, we had three significant purchasers that accounted for approximately 48%, 59% and 68%, 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.

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. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.”

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business.

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 where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — 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.”

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Competition

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions, as well as drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering, processing and compression opportunities, as well as salt water disposal activities in the areas in which we operate.

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, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities 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, to acquire properties and to provide competitive midstream services 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.”

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream 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 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 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.

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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 transparency in the market for the sale or transportation of 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, and intrastate crude oil gathering facilities are also exempt from FERC’s jurisdiction under the Interstate Commerce Act. 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, and that the crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or 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.

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.

The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, as amended. In recent years, pursuant to these laws and, in addition, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking (NPRM) that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but has yet to publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines.

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays.

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, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would 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.”

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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 as all other costs of drilling and completion of our wells and are included in 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, or the 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 and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking 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 fracturing operations 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 our fracturing operations 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. Since mid-2015, we have also been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us.

Environmental Regulation

The exploration, development, production, gathering and processing 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, midstream facilities and salt water injection and disposal 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. 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 do not expect that these laws and regulations will 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 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. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action.

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

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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. 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.

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 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.

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 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. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

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. Based on these findings, the Environmental Protection Agency, or the EPA, has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and 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. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.”

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, 2016, we owned and operated twelve underground injection wells 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 operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and

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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 federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 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.”

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 may occur, and we may 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 we operate. 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.

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. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation

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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 for more details regarding our office lease. Such information is incorporated herein by reference.

Employees

At December 31, 2016, we had 165 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, land, 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 midstream services, 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 Reports 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, Compensation Committee, Corporate Governance Committee, Executive Committee and Nominating 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 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 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 2016, the average price of oil was $43.40 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $2.55 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Starting in February and March of 2016, respectively, oil and natural gas prices began to increase from their most recent lows. Oil prices increased 106% from $26.21 per Bbl in mid-February 2016 to $54.06 per Bbl in late December 2016, and natural gas prices increased 140% from $1.64 per MMBtu in early March 2016 to $3.93 per MMBtu in late December 2016.

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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 of the quarters of 2015 and in the first two quarters of 2016, and should prices decline again, we may 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;


•	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. 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.

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Our Exploration, Development, Exploitation and Midstream 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, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners 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;


•	the costs of constructing, operating and maintaining our midstream facilities;


•	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 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 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 or joint venture of midstream assets or oil and natural gas producing assets or acreage, 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, geophysical and land costs, including 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.

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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 or participate in 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 of oil and natural gas from our properties by adjacent operators;


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


•	accidents, equipment failures or mechanical problems;


•	title defects of 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 exploration and production 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


•	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 a variety of factors, some of which may be beyond our control. As of February 22, 2017, our borrowing base was $400.0 million, and we had no outstanding borrowings under, and approximately $0.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. We could be required to repay a portion of any outstanding 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;

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•	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. Low oil and natural gas prices or any 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 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 22, 2017, we had available borrowings of approximately $399.2 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.

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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 22, 2017, 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. 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.

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, gathering and processing, 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;


•	damage to pipelines, processing plants and disposal wells and associated facilities;


•	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 and services, 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 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.

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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. In 2015 and 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. As a result, for the year ended December 31, 2016, approximately 57% of our total oil and natural gas production, including approximately 75% of our average daily oil production, was attributable to our properties in the Delaware Basin and approximately 18% of our total oil and natural gas production, including approximately 25% of our average daily oil production, was attributable to our properties in the Eagle Ford shale. At December 31, 2016, approximately 75% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. We expect that a significant portion of our operations in 2017 will be in the Delaware Basin.

The industry focus on the Delaware Basin 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. 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, in recent years the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures have resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In recent years, certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we

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may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should low oil or natural gas prices continue or should oil and natural gas prices decline further, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us.

In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows.

If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.

We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows.

Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:


•	the quality and quantity of available data;


•	the interpretation of that data;


•	the judgment of the persons preparing the estimate; and


•	the accuracy of the assumptions used.

The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be

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redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:


•	actual prices we receive for oil and natural gas;


•	actual costs and timing of development and production expenditures;


•	the amount and timing of actual production; and


•	changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate

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