Matador Resources Co - FORM 10-K

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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, 2017



¨	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. ¨

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



Large accelerated filer	ý		Accelerated filer	¨

Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

			Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 $1,910,451,565.

As of February 21, 2018, there were 109,248,747 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 2018 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, 2017

TABLE OF CONTENTS




		Page
PART I
ITEM 1.	Business	2
ITEM 1A.	Risk Factors	29
ITEM 1B.	Unresolved Staff Comments	53
ITEM 2.	Properties	53
ITEM 3.	Legal Proceedings	53
ITEM 4.	Mine Safety Disclosures	53

PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
ITEM 6.	Selected Financial Data	57
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	78
ITEM 8.	Financial Statements and Supplementary Data	79
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
ITEM 9A.	Controls and Procedures	80
ITEM 9B.	Other Information	83

PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	83
ITEM 11.	Executive Compensation	83
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	83
ITEM 14.	Principal Accounting Fees and Services	83

PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	84

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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,” “would” 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;


•	the ability of our midstream joint venture to attract third-party volumes;


•	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.

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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.

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 undertake no obligation 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 through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties.

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 play 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 and that generate value for San Mateo;


•	maintain our financial discipline; and


•	pursue opportunistic acquisitions, divestitures and joint ventures.

Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2017 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also continued to increase our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2017, including the formation of San Mateo in February 2017, the October 2017 public offering of 8,000,000 shares of our

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common stock and multiple increases in the borrowing base under our Credit Agreement (as defined below). These transactions increased our operational flexibility and opportunities and further strengthened our balance sheet.

For information about our segment reporting, see Note 17 to the consolidated financial statements in this Annual Report.

2017 Highlights

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2017, we achieved record oil, natural gas and average daily oil equivalent production. In 2017, we produced 7.9 million Bbl of oil, an increase of 54%, as compared to 5.1 million Bbl of oil produced in 2016. We also produced 38.2 Bcf of natural gas, an increase of 25% from 30.5 Bcf of natural gas produced in 2016. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40%, as compared to 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year ended December 31, 2016. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2017, but also to production from five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Oil production comprised 55% 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, 2017, as compared to 50% for the year ended December 31, 2016.

Increased Oil and Oil Equivalent Reserves

At December 31, 2017, our estimated total proved oil and natural gas reserves were 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, an increase of 44% from 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, at December 31, 2016. The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 119% and 129% to $1.26 billion and $1.33 billion, respectively, at December 31, 2017, from $575.0 million and $581.5 million, respectively, at December 31, 2016, primarily as a result of our ongoing delineation and development drilling activities 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 52% to 86.7 million Bbl at December 31, 2017 from 57.0 million Bbl at December 31, 2016. Our proved natural gas reserves increased 35% to 396.2 Bcf at December 31, 2017 from 292.6 Bcf at December 31, 2016. This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2017.

At December 31, 2017, proved developed reserves included 37.0 million Bbl of oil and 190.1 Bcf of natural gas, and proved undeveloped reserves included 49.8 million Bbl of oil and 206.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 45% and 57%, respectively, of our total proved oil and natural gas reserves at December 31, 2017. 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.

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 four 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 2018.

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We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin in 2017, including 65 gross (56.1 net) operated and 21 gross (3.5 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2017. As a result, at December 31, 2017, our total acreage position in the Delaware Basin had increased to approximately 199,600 gross (114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been pleased with the aggregate performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our seven 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 Antelope Ridge, 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 85% to 29,463 BOE per day (76% of total oil equivalent production), including 18,023 Bbl of oil per day (84% of total oil production) and 68.6 MMcf of natural gas per day (66% of total natural gas production), in 2017, as compared 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. We expect our Delaware Basin production to increase throughout 2018 as we continue the delineation and development of these asset areas.

Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2017 included:


•	in our Rustler Breaks asset area, the extension of Wolfcamp A-XY operations to the northwest region of the asset area, the initial testing of the Wolfcamp A-Lower interval and the continued delineation and development of previously tested horizons;


•	in our Jackson Trust asset area, the results from the Totum E 18-TTT-C24 NL #211H well, whose 24-hour initial potential test result and subsequent well performance marked the best result we have achieved in the Wolfcamp A-Lower interval in either the Wolf or Jackson Trust asset areas;


•	in our Wolf asset area, a positive first test of the Wolfcamp B interval;


•	in our Ranger asset area, the continued success of the three wells drilled and completed in the Third Bone Spring formation on our Mallon leasehold, which were placed on gas lift during the third quarter of 2017 and have together produced over 1.1 million Bbl of oil in just over one year of production;


•	in our Twin Lakes asset area, a positive test of the Wolfcamp D formation from the D. Culbertson 26-15S-36E TL State #234H well, our first horizontal well in the Twin Lakes asset area;


•	in our Arrowhead asset area, the drilling and completion of our first operated wells, which further illustrated the potential of the Second Bone Spring and the Third Bone Spring in our northern Delaware Basin acreage position;


•	in our Antelope Ridge asset area, the drilling of our first two operated wells, the first of which was completed in early 2018 and was a positive test of the Wolfcamp A interval that we believe confirms the prospectivity of the Antelope Ridge asset area; and

•

the significant progress made in our midstream operations, including (i) the ongoing expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”), (ii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas and (iii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks and Wolf asset areas, significantly increasing San Mateo’s salt water disposal capacity in these asset areas.

We also completed and began producing oil and natural gas from eight gross (5.8 net) wells in the Eagle Ford shale in South Texas in 2017, including five gross (5.0 net) operated and three gross (0.8 net) non-operated wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017, although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that began producing in 2017.

Financing Arrangements

On October 10, 2017, we completed a public offering of 8,000,000 shares of our common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, leasehold and mineral acquisitions and general corporate purposes, including to fund a portion of our current and future capital expenditures.

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Midstream Joint Venture

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 that were contributed to San Mateo included (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 salt 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 San Mateo. Through January 31, 2018, we had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn up to an additional $58.8 million in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues 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.

2018 Recent Developments

On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and around the Rustler Breaks asset area. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase our oil production in the Rustler Breaks and Wolf asset areas.

Exploration and Production Segment

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. During 2017, 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 for the year ended December 31, 2017, essentially all of our efforts were focused on unconventional plays.

The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2017.



			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⁾	199,600	114,000	450	211.5	4,630	1,957.7	128,999	40.6	29,463
South Texas:
Eagle Ford ⁽⁵⁾	31,800	29,000	142	119.8	241	208.5	12,346	72.2	4,413
Northwest Louisiana/East Texas:
Haynesville	19,600	12,000	217	20.5	413	102.0	10,106	59.5	4,697
Cotton Valley ⁽⁶⁾	21,100	18,600	81	54.3	71	50.0	1,320	100.0	363
Area Total ⁽⁷⁾	25,500	22,800	298	74.8	484	152.0	11,426	64.1	5,060
Total	256,900	165,800	890	406.1	5,355	2,318.2	152,771	44.9	38,936

__________________

(1)

Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2017. 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, 2017, these engineered drilling locations included only 261 gross (130.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations in the Delaware Basin, 12 gross (12.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and nine gross (3.3 net) locations to which we have assigned proved undeveloped reserves in the Haynesville.

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(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)	Production volumes and proved reserves reported in two streams; oil and natural gas, including both dry and liquids-rich natural gas. 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, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2017.


(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.

We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2017, 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, 2017, we also were the operator for approximately 94% of our Eagle Ford acreage and approximately 64% 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 an affiliate of Chesapeake Energy Corporation.

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 Brushy Canyon, 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 “—2017 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2017, and as a result, at December 31, 2017, our total acreage position in Southeast New Mexico and West Texas was approximately 199,600 gross (114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 28,800 gross (15,500 net) acres in our Ranger asset area in Lea County, 56,600 gross (23,400 net) acres in our Arrowhead asset area in Eddy County, 41,000 gross (21,200 net) acres in our Rustler Breaks asset area in Eddy County, 12,000 gross (8,900 net) acres in our Antelope Ridge asset area in Lea County, 13,600 gross (9,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 46,100 gross (34,400 net) acres in our Twin Lakes asset area in Lea County at December 31, 2017. 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

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and Morrow formations. At December 31, 2017, our acreage position in the Delaware Basin was approximately 45% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical and one horizontal well, our acreage position in the Delaware Basin was approximately 59% held by existing production at December 31, 2017.

During the year ended December 31, 2017, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin, including 65 gross (56.1 net) operated wells and 21 gross (3.5 net) non-operated wells, throughout our various asset areas. At December 31, 2017, 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 2017. Our average daily oil equivalent production from the Delaware Basin increased approximately 85% to 29,463 BOE per day (76% of total oil equivalent production), including 18,023 Bbl of oil per day (84% of total oil production) and 68.6 MMcf of natural gas per day (66% of total natural gas production), in 2017, as compared 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. Our average daily oil equivalent production from the Delaware Basin also grew approximately 69% from 20,670 BOE per day in the fourth quarter of 2016 to 34,859 BOE per day in the fourth quarter of 2017.

At December 31, 2017, approximately 84% of our estimated total proved oil and natural gas reserves, or 129.0 million BOE, was attributable to the Delaware Basin, including approximately 77.5 million Bbl of oil and 308.9 Bcf of natural gas, a 62% increase, as compared to 79.4 million BOE for the year ended December 31, 2016. Our Delaware Basin proved reserves at December 31, 2017 comprised approximately 89% of our proved oil reserves and 78% of our proved natural gas reserves, as compared to approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves at December 31, 2016.

At December 31, 2017, we had identified 4,630 gross (1,957.7 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 Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 2,954 gross (1,775.5 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, 2017 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 second anticipated operated horizontal test of the Wolfcamp D formation in 2018). Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible, at December 31, 2017, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2017, these potential future drilling locations included only 261 gross (130.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves.

At December 31, 2017, we were operating six drilling rigs in the Delaware Basin, and we expect to operate those rigs in the Delaware Basin throughout 2018, including three rigs in the Rustler Breaks asset area, one rig in the Wolf/Jackson Trust asset areas, one rig in the Ranger/Arrowhead and Twin Lakes asset areas and one rig in the Antelope Ridge asset area. One of the three rigs operating in the Rustler Breaks asset area is also expected to drill at least two commercial salt water disposal wells in that area during 2018 for San Mateo. As a result, we expect that this rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2018. We have allocated substantially all of our 2018 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.

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Rustler Breaks Asset Area - Eddy County, New Mexico

We operated three drilling rigs in our Rustler Breaks asset area during most of 2017. We completed and turned to sales 53 gross (34.5 net) horizontal wells in the Rustler Breaks asset area in 2017, including 37 gross (32.4 net) operated and 16 gross (2.1 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY or Wolfcamp B-Blair intervals, and the well results achieved were consistent with previous wells drilled and completed in those intervals.

One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2017 was the success of our wells drilled in the northwestern portion of our acreage position. Early performance from these wells is comparable to or better than Wolfcamp A-XY wells in other portions of our Rustler Breaks asset area. As examples, the Joe Coleman 13-23S-27E RB #206H (Joe Coleman #206H) and the Tom Walters 12-23S-27E RB #203H (Tom Walters #203H) wells tested 1,840 BOE per day (75% oil) and 1,554 BOE per day (74% oil), respectively, during 24-hour initial potential tests. In just nine months of production, the Joe Coleman #206H well has produced approximately 275,000 BOE (71% oil), and in approximately one year of production, the Tom Walters #203H well has produced approximately 255,000 BOE (73% oil).

In addition, two Wolfcamp A-Lower wells completed in 2017 represented our first tests of the Wolfcamp A-Lower interval in the Rustler Breaks asset area. The Guitar 10-24S-28E RB #205H well tested 1,155 BOE per day (75% oil) and the Charlie Sweeney Fed Com #204H well tested 1,188 BOE per day (75% oil), during 24-hour initial potential tests. We believe that these tests confirm the potential of the Wolfcamp A-Lower interval as another completion target in the Rustler Breaks asset area.

Wolf and Jackson Trust Asset Areas - Loving County, Texas

In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY, Wolfcamp A-Lower and Second Bone Spring formations in 2017. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2017, and we completed and turned to sales 13 gross (11.0 net) operated horizontal wells in these asset areas. Most of these wells were completed in the Wolfcamp A-Lower and Second Bone Spring intervals.

In early January 2017, we completed and placed on production the Totum E 18-TTT-C24 NL #211H (Totum #211H) well. This well tested 2,247 BOE per day (72% oil) during a 24-hour initial potential test, which was the highest 24-hour initial potential test for any Wolfcamp A-Lower well completed by us in either our Wolf or Jackson Trust asset areas. We attribute this significant improvement in well performance to both the selection of an improved landing target, identified through the use of 3-D seismic data, and an improved stimulation design. In almost one year of production, the Totum #211H well has produced approximately 300,000 BOE (77% oil).

The Barnett 90-TTT-B01 WF #224H (Barnett #224H) well was our first test of the Wolfcamp B interval in our Wolf asset area. The Barnett #224H well tested 1,803 BOE per day (28% oil) at 4,125 psi during a 24-hour initial potential test. This well exhibited the highest flowing casing pressure on any well yet completed by us in the Wolf asset area. The initial test results and early performance from the Barnett #224H well exceeded our expectations and were similar to those from the Wolfcamp B-Blair interval in the Rustler Breaks asset area. We were pleased with the results of this initial test of the Wolfcamp B interval, which we believe confirms the potential of the Wolfcamp B interval as another completion target in the Wolf asset area.

Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico

We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2017. We completed and turned to sales 18 gross (13.4 net) horizontal wells in these asset areas in 2017, including 15 gross (12.7 net) operated and three gross (0.7 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals.

In the second and third quarters of 2017, we completed and turned to sales our first operated horizontal wells in our Arrowhead asset area on our Stebbins leasehold. The Stebbins 20 Federal #123H (Stebbins 20 #123H) well was a Second Bone Spring test, and the Stebbins 20 Federal #133H (Stebbins 20 #133H) well was a Third Bone Spring test. The Stebbins 20 #123H and #133H wells tested 1,010 BOE per day (82% oil) and 1,202 BOE per day (70% oil), respectively, during 24-hour initial potential tests. We completed and turned to sales three additional wells on the Stebbins leasehold in the fourth quarter of 2017, two completed in the Second Bone Spring interval and one completed in the Third Bone Spring interval, with comparable 24-hour initial potential test results to the initial Stebbins wells.

The contiguous nature of the Stebbins acreage has already lent itself to several operational efficiencies, such as batch drilling and completion operations, as well as centralized facilities, each of which contribute to lower overall project costs. Drilling times for the Stebbins wells have improved by as much as 4.1 days since development began on the Stebbins leasehold in 2017. In addition, we expect to be able to drill 1.5 and 2-mile laterals as part of our future development of this acreage.

In the Ranger asset area, we drilled the Airstrip 31-18S-35E RN State Com #132H (Airstrip #132H) well, a Third Bone Spring test north of our Mallon leasehold. The Airstrip #132H well tested 1,263 BOE per day (93% oil) during a 24-hour initial potential test. The Airstrip #132H well has produced approximately 95,000 BOE (92% oil) in its first six months of production.

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During the third quarter of 2017, we installed gas lift on the three Mallon wells—the Mallon 27 Federal Com #1H, #2H and #3H (Mallon #1H, #2H and #3H) wells in the Ranger asset area. Each of these three wells was drilled and completed in the Third Bone Spring and turned to sales in the fourth quarter of 2016. The Mallon wells each tested initially between 2,400 and 2,800 BOE per day (91% oil) and continued to perform well throughout their first ten to eleven months of production prior to the installation of gas lift. Unlike most Third Bone Spring wells completed in the Arrowhead and Ranger asset areas, these wells were tested while flowing up casing (rather than on electrical submersible pump), and the wells continued to flow up casing until the installation of gas lift on each well in the third quarter of 2017.

Each of the Mallon wells exhibited a strong production response to the installation of gas lift. Daily production rates from the Mallon #1H well, which had declined to 600 to 700 Bbl of oil per day, increased to an average of over 1,300 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #2H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of almost 1,500 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #3H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of approximately 900 Bbl of oil per day in the first 30 days following gas lift installation. Natural gas production from these wells responded in a similar fashion. Production declines resumed on these wells at a similar rate to what was observed prior to the installation of gas lift, but from higher daily production rates. The three Mallon wells have produced about 1.3 million BOE (90% oil) in the aggregate, including over 1.1 million Bbl of oil in just over one year of production.

Twin Lakes Asset Area - Lea County, New Mexico

In 2017, we performed our first horizontal test of the Wolfcamp D formation in the eastern portion of our Twin Lakes asset area in northern Lea County, New Mexico. This well, the D. Culbertson 26-15S-36E TL State #234H (D. Culbertson #234H) well, tested approximately 600 BOE per day (82% oil) during a 24-hour initial potential test, including 493 Bbl of oil per day and 640 Mcf of natural gas per day, from a completed lateral length of approximately 4,400 feet. We were pleased and encouraged with the initial results from this discovery well, which we believe confirmed our exploration concept and validated the prospectivity of the Wolfcamp D in the Twin Lakes asset area. To our knowledge, this discovery well is the northernmost horizontal test of the Wolfcamp formation in New Mexico, and this well demonstrates the potential for horizontal exploitation and development of the Wolfcamp formation far to the north of the most active areas of current drilling in the Wolfcamp play in the Delaware Basin. Overall, the D. Culbertson #234H well provided us with a solid first step in our understanding of the Wolfcamp D formation in this area. We plan to drill a second Wolfcamp D test on the western portion of our Twin Lakes acreage position in 2018.

Antelope Ridge Asset Area - Lea County, New Mexico

We drilled our first operated well in the Antelope Ridge asset area, the Florence State 23-23S-34E #202H (Florence #202H) well, in mid-November 2017. This well was completed and turned to sales in January 2018. The Florence #202H well tested 1,947 BOE per day (81% oil) at 1,700 psi during a 24-hour initial potential test. We were pleased with the initial performance of this well and believe it confirms the prospectivity of the Antelope Ridge asset area. We intend to continue the delineation of our acreage position in Antelope Ridge, where other operators in the area have successfully tested the Brushy Canyon, First, Second and Third Bone Spring and Upper Wolfcamp intervals.

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, 2017, our properties included approximately 31,800 gross (29,000 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, with the remainder being prospective for less liquids-rich natural gas. Approximately 86% of our Eagle Ford acreage was held by production at December 31, 2017, and approximately 98% of our Eagle Ford acreage was either held by production at December 31, 2017 or not burdened by lease expirations before 2019.

In 2017, we drilled and completed five operated wells in the Eagle Ford shale in South Texas. Two of these wells, the Falls City #1H and #2H wells, both located in Karnes County, were turned to sales in mid-June 2017. The other three wells, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells, all located in La Salle County, were turned to sales in early July 2017. We have a 100% working interest in each of these five wells. These five Eagle Ford shale wells tested

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between approximately 1,100 and 1,700 BOE per day at oil cuts between 90% and 94% during 24-hour initial potential tests. The initial results from this five-well drilling program almost doubled our average daily oil equivalent production from the Eagle Ford shale in the third quarter of 2017, as compared to production levels in the second quarter of 2017.

At December 31, 2017, the Falls City #1H and #2H wells had the highest estimated ultimate oil recoveries of any of our wells in the Eagle Ford shale. Further, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells were drilled and completed for an average of approximately $4.5 million per well, among the lowest well costs we have achieved in the Eagle Ford shale. Despite not being active in the Eagle Ford shale since the second quarter of 2015, we were able to achieve our fastest drilling time for an Eagle Ford shale well from spud to total depth in one of these Martin Ranch wells.

Our average daily oil equivalent production from the Eagle Ford shale decreased 11% to 4,413 BOE per day, including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017, as compared 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. For the year ended December 31, 2017, 11% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2016, approximately 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale.

At December 31, 2017, approximately 8% of our estimated total proved oil and natural gas reserves, or 12.3 million BOE, was attributable to the Eagle Ford shale, including approximately 9.2 million Bbl of oil and 19.0 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 11% of our proved oil reserves and 5% of our proved natural gas reserves at December 31, 2017, as compared to approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016.

At December 31, 2017, we had identified 241 gross (208.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate 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. At December 31, 2017, these 241 gross (208.5 net) identified drilling locations included only 12 gross (12.0 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 other 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, 2017, 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, even though recent activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals.

Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations

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 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 did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017, although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that were turned to sales in 2017. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2018.

At December 31, 2017, we held approximately 25,500 gross (22,800 net) acres in Northwest Louisiana and East Texas, including 19,600 gross (12,000 net) acres in the Haynesville shale play and 21,100 gross (18,600 net) acres in the Cotton Valley

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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. We believe the core area of the play includes that area in which the most Haynesville shale wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well from an approximate 5,000-foot horizontal lateral.

For the year ended December 31, 2017, approximately 13% of our average daily oil equivalent production, or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 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 29% of our daily natural gas production for 2017, but oil production from these properties comprised only about 0.1% of our daily oil production during 2017, as compared to approximately 50% of our daily natural gas production and approximately 0.1% of our daily oil production during 2016. During 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 properties in Northwest Louisiana and East Texas.

For the year ended December 31, 2017, approximately 27% of our daily natural gas production, or 28.3 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 2%, or 2.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. 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. At December 31, 2017, approximately 7% of our estimated total proved reserves, or 10.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage.

At December 31, 2017, we had identified 413 gross (102.0 net) engineered locations for potential future drilling in the Haynesville shale play and 71 gross (50.0 net) engineered locations for potential future drilling in the Cotton Valley formation. 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 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 413 gross (102.0 net) locations identified for future drilling on our Haynesville acreage, 339 gross (49.0 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, 2017, these potential future drilling locations included only nine gross (3.3 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves.

Midstream Segment

The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. 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. As noted above, we contributed the Delaware Midstream Assets to San Mateo in February 2017 and continued to operate them, as well as San Mateo’s other assets, at December 31, 2017.

Southeast New Mexico and West Texas — Delaware Basin

During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental 200 MMcf per day to the existing 60 MMcf per day of inlet cryogenic natural gas processing capacity. At February 21, 2018, the expansion project was proceeding on schedule with the plant expansion expected to become operational by the end of the first quarter of 2018. At December 31, 2017 and February 21, 2018, the Black River Processing Plant was effectively full with Matador-operated natural gas. The Black River Processing Plant and associated gathering system were built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm 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 after the plant expansion becomes operational. 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 October 2017 and January 2018, San Mateo placed into service its second and third, respectively, commercial salt water disposal wells in the Rustler Breaks

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asset area. San Mateo disposed of approximately 7.9 million Bbl of Matador-operated and third-party salt water in the Rustler Breaks asset area during 2017 and, at February 21, 2018, its salt water disposal wells there had a disposal capacity of approximately 90,000 Bbl of salt water per day. San Mateo plans to add to that disposal capacity in 2018 by upgrading two of the existing salt water disposal wells by installing larger tubing and drilling and completing at least two additional commercial salt water disposal wells and constructing the associated commercial salt water disposal facilities in the Rustler Breaks asset area. We expect these additional wells to be completed in 2018, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to a total of five. At February 21, 2018, San Mateo was also building out an oil gathering and transportation system in the Rustler Breaks asset area.

In our Wolf asset area in Loving County, Texas, San Mateo has oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production. 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 an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo in February 2017. During 2017, San Mateo disposed of approximately 15.5 million Bbl of salt water in the Wolf asset area, including disposal of third-party salt water on a commercial basis. San Mateo completed its third salt water disposal well in the Wolf asset area during 2017, increasing San Mateo’s disposal capacity in the Wolf asset area to approximately 70,000 Bbl of salt water per day. At February 21, 2018, San Mateo was also expanding its oil gathering system in the Wolf asset area.

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 and from third parties. We also have five 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.

Operating Summary

The following table sets forth certain unaudited production and operating data for the years ended December 31, 2017, 2016 and 2015.



	Year Ended December 31,
	2017		2016		2015
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl)	7,851		5,096		4,492
Natural gas (Bcf)	38.2		30.5		27.7
Total oil equivalent (MBOE) ⁽¹⁾	14,212		10,180		9,109
Average daily production (BOE/d) ⁽¹⁾	38,936		27,813		24,955
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	49.28	$	41.19	$	45.27
Oil, with realized derivatives (per Bbl)	$	48.81	$	42.34	$	59.13
Natural gas, without realized derivatives (per Mcf)	$	3.72	$	2.66	$	2.71
Natural gas, with realized derivatives (per Mcf)	$	3.70	$	2.78	$	3.24
Operating Expenses (per BOE):
Production taxes, transportation and processing	$	4.10	$	4.23	$	3.91
Lease operating	$	4.74	$	5.52	$	6.01
Plant and other midstream services operating	$	0.92	$	0.53	$	0.38
Depletion, depreciation and amortization	$	12.49	$	11.99	$	19.63
General and administrative	$	4.65	$	5.41	$	5.50

__________________


(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 information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 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)	6,579			1,268			—			4			7,851
Natural gas (Bcf)	25.1			2.0			10.3			0.8			38.2
Total oil equivalent (MBOE) ⁽³⁾	10,754			1,611			1,714			133			14,212
Percentage of total annual net production	75.7		%	11.3		%	12.1		%	0.9		%	100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)	18,023			3,475			—			12			21,510
Natural gas (MMcf/d)	68.6			5.6			28.3			2.1			104.6
Total oil equivalent (BOE/d)	29,463			4,413			4,697			363			38,936
Average Sales Prices⁽⁴⁾
Oil (per Bbl)	$	49.08		$	50.29		$	—		$	45.52		$	49.28
Natural gas (per Mcf)	$	4.03		$	4.69		$	2.83		$	2.79		$	3.72
Total oil equivalent (per BOE)	$	39.41		$	45.58		$	16.96		$	17.69		$	37.20
Production Costs ⁽⁵⁾
Lease operating, transportation and processing (per BOE)	$	5.80		$	10.92		$	4.21		$	16.77		$	6.29

__________________


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


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


(3)	Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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.

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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, 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.


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


(3)	Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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.

Table of Contents

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


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


(3)	Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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 14.2 million BOE for the year ended December 31, 2017 increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016. 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. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to 27,813 BOE per day for the year ended December 31, 2016. Our average daily oil production for the year ended December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year ended December 31, 2016. Our average daily natural gas production for the year ended December 31, 2017 was 104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended December 31, 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, as of December 31, 2016, we had 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.

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Producing Wells

The following table sets forth information relating to producing wells at December 31, 2017. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 75% in all wells that we operated at December 31, 2017. 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 11%. 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⁾	372	174.8	78	36.7	450	211.5
South Texas:
Eagle Ford⁽²⁾	138	115.8	4	4.0	142	119.8
Northwest Louisiana/East Texas:
Haynesville	—	—	217	20.5	217	20.5
Cotton Valley ⁽³⁾	2	2.0	79	52.3	81	54.3
Area Total	2	2.0	296	72.8	298	74.8
Total	512	292.6	378	113.5	890	406.1

__________________


(1)	Includes 217 gross (55.4 net) vertical wells that were acquired in multiple transactions.


(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, 2017, 2016 and 2015. 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 (“NGLs”) associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs 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⁾
	2017			2016			2015
Estimated Proved Reserves Data: ⁽²⁾
Estimated proved reserves:
Oil (MBbl)	86,743			56,977			45,644
Natural Gas (Bcf) ⁽³⁾	396.2			292.6			236.9
Total (MBOE) ⁽⁴⁾	152,771			105,752			85,127
Estimated proved developed reserves:
Oil (MBbl)	36,966			22,604			17,129
Natural Gas (Bcf) ⁽³⁾	190.1			126.8			101.4
Total (MBOE) ⁽⁴⁾	68,651			43,731			34,037
Percent developed	44.9		%	41.4		%	40.0		%
Estimated proved undeveloped reserves:
Oil (MBbl)	49,777			34,373			28,515
Natural Gas (Bcf) ⁽³⁾	206.1			165.9			135.5
Total (MBOE)⁽⁴⁾	84,120			62,021			51,090
Standardized Measure ⁽⁵⁾ (in millions)	$	1,258.6		$	575.0		$	529.2
PV-10 ⁽⁶⁾ (in millions)	$	1,333.4		$	581.5		$	541.6

__________________


(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, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas, for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, and for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 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 NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs 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, 2017, 2016 and 2015 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, 2017, 2016 and 2015 were, in millions, $74.8, $6.5 and $12.4, respectively.

Our estimated total proved oil and natural gas reserves increased 44% from 105.8 million BOE at December 31, 2016 to 152.8 million BOE at December 31, 2017. We added 45.2 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2017, approximately 3.2 times our 2017 annual production of 14.2 million BOE. Our proved oil reserves grew 52% from approximately 57.0 million Bbl at December 31, 2016 to approximately 86.7 million Bbl at December 31, 2017. Our proved natural gas reserves increased 35% from 292.6 Bcf at December 31, 2016 to 396.2 Bcf at December 31, 2017. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2017. We incurred approximately 9.6 million BOE in net upward revisions to our proved reserves during 2017 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017, as compared to December 31, 2016. Our proved reserves to production ratio at December 31, 2017 was 10.8x, an increase of 4% from 10.4x at December 31, 2016.

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The Standardized Measure of our total proved oil and natural gas reserves increased 119% from $575.0 million at December 31, 2016 to $1.26 billion at December 31, 2017. The PV-10 of our total proved oil and natural gas reserves increased 129% from $581.5 million at December 31, 2016 to $1.33 billion at December 31, 2017. The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2017 and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017, as compared to December 31, 2016. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2017 were $47.79 per Bbl and $2.98 per MMBtu, an increase of 22% and 20%, respectively, as compared to average oil and natural gas prices of $39.25 per Bbl and $2.48 per MMBtu used to estimate proved reserves at December 31, 2016. Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2017, as compared to 54% oil and 46% natural gas at December 31, 2016.

Our proved developed oil and natural gas reserves increased 57% from 43.7 million BOE at December 31, 2016 to 68.7 million BOE at December 31, 2017 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 64% from 22.6 million Bbl at December 31, 2016 to 37.0 million Bbl at December 31, 2017. Our proved developed natural gas reserves increased 50% from 126.8 Bcf at December 31, 2016 to 190.1 Bcf at December 31, 2017.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2017.



	Proved Developed Reserves
	Proved Developed Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2016	43,731
Extensions and discoveries	14,335
Purchases of minerals-in-place	1,614
Revisions of prior estimates	6,375
Production	(14,212	)
Conversion of proved undeveloped to proved developed	16,808
As of December 31, 2017	68,651

__________________


(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 36% from 62.0 million BOE at December 31, 2016 to 84.1 million BOE at December 31, 2017. Our proved undeveloped oil and natural gas reserves increased from 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 to 49.8 million Bbl and 206.1 Bcf, respectively, at December 31, 2017, primarily as a result of our delineation and development operations in the Delaware Basin.

At December 31, 2017, 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, 2017 within five years of booking these reserves.

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2017.



	Proved Undeveloped Reserves
	Proved Undeveloped Reserves
	(MBOE) ⁽¹⁾
As of December 31, 2016	62,021
Extensions and discoveries	30,834
Purchases of minerals-in-place	4,868
Revisions of prior estimates	3,205
Conversion of proved undeveloped to proved developed	(16,808	)
As of December 31, 2017	84,120

__________________


(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 2014, 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⁾
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
2017	9,300	45.0	16,808	211,860
Total	20,639	126.2	41,661	$	613,378

__________________


(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, 2017.



	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	77,508	308.9	128,999	$	1,088.4	$	1,153.1
South Texas:
Eagle Ford ⁽⁵⁾	9,189	19.0	12,346	130.6		138.4
Northwest Louisiana/East Texas:
Haynesville	—	60.7	10,106	35.7		37.8
Cotton Valley ⁽⁶⁾	46	7.6	1,320	3.9		4.1
Area Total	46	68.3	11,426	39.6		41.9
Total	86,743	396.2	152,771	$	1,258.6	$	1,333.4

__________________


(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, 2017 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, 2017 were approximately $74.8 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 40 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 as well.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2017.



	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin	100,500	50,600	99,100	63,400	199,600	114,000
South Texas:
Eagle Ford	27,600	24,900	4,200	4,100	31,800	29,000
Northwest Louisiana/East Texas:
Haynesville	16,200	8,600	3,400	3,400	19,600	12,000
Cotton Valley	17,600	15,600	3,500	3,000	21,100	18,600
Area Total ⁽¹⁾	21,500	19,300	4,000	3,500	25,500	22,800
Total	149,600	94,800	107,300	71,000	256,900	165,800

__________________


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

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2017 that will expire over the next four 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 2022 and beyond represents an immaterial amount of our overall undeveloped acreage.

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	Acres		Acres		Acres		Acres
	Expiring 2018		Expiring 2019		Expiring 2020		Expiring 2021
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Southeast New Mexico/West Texas:
Delaware Basin ⁽¹⁾	25,600	18,900	14,400	11,300	8,900	7,800	19,000	11,700
South Texas:
Eagle Ford	900	700	1,500	1,400	1,600	1,600	—	—
Northwest Louisiana/East Texas:
Haynesville	—	—	300	300	200	200	—	—
Cotton Valley	—	—	—	—	—	—	—	—
Area Total ⁽²⁾	—	—	300	300	200	200	—	—
Total	26,500	19,600	16,200	13,000	10,700	9,600	19,000	11,700

__________________


(1)	Approximately 59% of the acreage expiring in the Delaware Basin in the next four years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of the expiring acreage through our 2018 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, or top 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, 2017, 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, 2017, 2016 and 2015.



	Year Ended December 31,
	2017		2016		2015
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	72	43.7	44	23.5	53	26.7
Dry	—	—	—	—	—	—
Exploration Wells
Productive	33	22.3	28	15.6	28	17.5
Dry	—	—	—	—	—	—
Total Wells
Productive	105	66.0	72	39.1	81	44.2
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.

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 to both unaffiliated independent marketing companies and unaffiliated midstream companies.

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The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s 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 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.”

For the years ended December 31, 2017, 2016 and 2015, we had four, three and three significant purchasers, respectively, that accounted for approximately 60%, 48% and 59%, respectively, of our total oil, natural gas and NGL revenues. Due to the nature of the markets for oil, natural gas and NGLs, 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. We expect that 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 and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability.

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 could 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, Provide Midstream Services 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.

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 and produced 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 NGLs 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. Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s

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jurisdiction under the Interstate Commerce Act, or the ICA. We believed, as of February 21, 2018, that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and the crude oil pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation.

In 2005, Congress enacted the 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.

At February 21, 2018, San Mateo was developing a common carrier pipeline that we expect to be subject to regulation by FERC under the ICA and the Energy Policy Act of 1992, or EP Act. The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative.

The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, 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 regulations promulgated by state regulatory commissions, which vary 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, each as amended. In recent years, pursuant to these laws and 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 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 did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. 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.

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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” and “Risk Factors — Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.”

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 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 proppants. We use major hydraulic fracturing service companies that 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

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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 and remediation 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 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 are 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. 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 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 NGLs 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

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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, 2017, we owned and operated over fifteen 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 operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. 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.” Hydraulic fracturing 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. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. 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, produced water 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

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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 and other areas in which we operate. 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 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 generally do not 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, 2017, we had 217 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 and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, 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.

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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, Strategic Planning and 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. 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 third amended and restated revolving credit agreement, as amended (the “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 2017, the average price of oil was $50.80 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 $3.02 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Starting in the first quarter of 2017, oil and natural gas prices began to increase from their previous lows. Oil prices increased 42% from $42.53 per Bbl in late June 2017 to $60.42 per Bbl in late December 2017, and natural gas prices increased 34% from $2.56 per MMBtu in late February 2017 to $3.42 per MMBtu in mid-May 2017, but had declined to $2.60 per MMBtu in late December 2017.

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;


•	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 oil, natural gas and NGLs;


•	the availability of refining capacity;


•	the prices and availability of alternative fuel sources;

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•	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 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 there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or to cease or delay further expansion of our midstream projects, 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.

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.

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 attract third-party customers for our midstream services;


•	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 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

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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 opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, 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 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. 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.

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;


•	the existence or magnitude of faults or unanticipated geological features;


•	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, other operators and service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following:

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•	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.

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, transportation 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.

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, 2016 and 2017, the vast majority of our capital expenditures were allocated to

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the Delaware Basin. We expect that substantially all of our capital expenditures in 2018 will continue to be in the Delaware Basin.

The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil, condensate and salt water 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, 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.

Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin.

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.

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.

As of February 21, 2018, the maximum facility amount under the Credit Agreement was $500.0 million and our elected borrowing commitment was $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing

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base, maximum facility amount and elected borrowing commitment. At February 21, 2018, we had available borrowings of approximately $397.9 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments.

In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement), we may incur significant amounts of additional indebtedness, including under our Credit Agreement, through the issuance of additional notes or otherwise, in order to fund acquisitions, develop our properties or invest in certain 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.

The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination, and We Are Subject to Interest Rate Risk under Our Credit Agreement.

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 21, 2018, our borrowing base was $525.0 million, and we had no outstanding borrowings under, and approximately $2.1 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 21, 2018, the maximum facility amount under the Credit Agreement was $500.0 million and our elected borrowing commitment was $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. 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.

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

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

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


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


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


•	transfer or sell assets;


•	make certain investments;


•	create certain liens;


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


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


•	engage in transactions with affiliates; and


•	create unrestricted subsidiaries.

A breach of any of these covenants could result in an event of default under our Credit Agreement and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. 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.

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

As of February 21, 2018, 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.

We Depend upon Several Significant Purchasers for the Sale of Most of Our Oil and Natural Gas Production. The Loss of One or More of These Purchasers Could, Among Other Factors, Limit Our Access to Suitable Markets for the Oil and Natural Gas We Produce.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2017, 2016 and 2015, we had four, three and three significant purchasers, respectively, that collectively accounted for approximately 60%, 48% and 59%, respectively, of our total oil, natural gas and NGL revenues. We cannot assure you that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows.

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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 or a particular operating area 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 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 oil and natural gas prices decline, 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.

Matador Resources Co - FORM 10-K - February 28, 2018

Attached files