10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ________________________________________________________ 

FORM 10-Q

 _________________________________________________________  

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

For the quarterly period ended June 30, 2017

OR

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

For the transition period from             to            

Commission File Number 001-35410

_________________________________________________________  

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
(Address of principal executive offices)	(Zip Code)

(972) 371-5200

(Registrant’s telephone number, including area code)

 _________________________________________________________

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.     x  Yes    ¨  No

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

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

Large accelerated filer	x	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    x  No

As of August 2, 2017, there were 100,437,295 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2017

INDEX

	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements - Unaudited	3
Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016	3
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016	4
Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2017	5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3. Quantitative and Qualitative Disclosures About Market Risk	41
Item 4. Controls and Procedures	41
PART II — OTHER INFORMATION	42
Item 1. Legal Proceedings	42
Item 1A. Risk Factors	42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 6. Exhibits	42
SIGNATURES	43

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements — Unaudited

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data)

	June 30, 2017			December 31, 2016
ASSETS
Current assets
Cash	$	131,466		$	212,884
Restricted cash	15,040			1,258
Accounts receivable
Oil and natural gas revenues	39,621			34,154
Joint interest billings	37,387			19,347
Other	7,303			5,167
Derivative instruments	7,067			—
Lease and well equipment inventory	2,957			3,045
Prepaid expenses and other assets	5,946			3,327
Total current assets	246,787			279,182
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,694,766			2,408,305
Unproved and unevaluated	567,009			479,736
Other property and equipment	204,299			160,795
Less accumulated depletion, depreciation and amortization	(1,939,570		)	(1,864,311		)
Net property and equipment	1,526,504			1,184,525
Other assets
Derivative instruments	2,992			—
Other assets	793			958
Total other assets	3,785			958
Total assets	$	1,777,076		$	1,464,665
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	7,371		$	4,674
Accrued liabilities	151,336			101,460
Royalties payable	35,423			23,988
Amounts due to affiliates	5,865			8,651
Derivative instruments	1,192			24,203
Advances from joint interest owners	5,468			1,700
Amounts due to joint ventures	4,873			4,251
Other current liabilities	656			578
Total current liabilities	212,184			169,505
Long-term liabilities
Senior unsecured notes payable	573,988			573,924
Asset retirement obligations	22,391			19,725
Derivative instruments	—			751
Amounts due to joint ventures	—			1,771
Other long-term liabilities	6,142			7,544
Total long-term liabilities	602,521			603,715
Commitments and contingencies (Note 10)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 100,399,756 and 99,518,764 shares issued; and 100,324,852 and 99,511,931 shares outstanding, respectively	1,004			995
Additional paid-in capital	1,453,341			1,325,481
Accumulated deficit	(563,858		)	(636,351		)
Treasury stock, at cost, 74,904 and 6,833 shares, respectively	(745		)	—
Total Matador Resources Company shareholders’ equity	889,742			690,125
Non-controlling interest in subsidiaries	72,629			1,320
Total shareholders’ equity	962,371			691,445
Total liabilities and shareholders’ equity	$	1,777,076		$	1,464,665

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

3

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data)

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2017			2016			2017			2016
Revenues
Oil and natural gas revenues	$	113,764		$	69,336		$	228,611		$	113,262
Third-party midstream services revenues	2,099			918			3,654			1,391
Realized gain (loss) on derivatives	558			2,465			(1,661		)	9,528
Unrealized gain (loss) on derivatives	13,190			(26,625		)	33,821			(33,464		)
Total revenues	129,611			46,094			264,425			90,717
Expenses
Production taxes, transportation and processing	12,875			10,556			24,682			18,459
Lease operating	16,040			12,183			31,797			26,695
Plant and other midstream services operating	2,942			1,061			5,283			2,088
Depletion, depreciation and amortization	41,274			31,248			75,266			60,170
Accretion of asset retirement obligations	314			289			614			552
Full-cost ceiling impairment	—			78,171			—			158,633
General and administrative	17,177			13,197			33,515			26,360
Total expenses	90,622			146,705			171,157			292,957
Operating income (loss)	38,989			(100,611		)	93,268			(202,240		)
Other income (expense)
Net gain on asset sales and inventory impairment	—			1,002			7			2,067
Interest expense	(9,224		)	(6,167		)	(17,679		)	(13,365		)
Other income	1,922			29			1,991			124
Total other expense	(7,302		)	(5,136		)	(15,681		)	(11,174		)
Net income (loss)	31,687			(105,747		)	77,587			(213,414		)
Net income attributable to non-controlling interest in subsidiaries	(3,178		)	(106		)	(5,094		)	(93		)
Net income (loss) attributable to Matador Resources Company shareholders	$	28,509		$	(105,853	)	$	72,493		$	(213,507	)
Earnings (loss) per common share
Basic	$	0.28		$	(1.15	)	$	0.72		$	(2.40	)
Diluted	$	0.28		$	(1.15	)	$	0.72		$	(2.40	)
Weighted average common shares outstanding
Basic	100,211			92,346			100,005			88,826
Diluted	100,227			92,346			100,455			88,826

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

4

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY - UNAUDITED

(In thousands)

For the Six Months Ended June 30, 2017

														Total shareholders’ equity attributable to Matador Resources Company
																	Non-controlling interest in subsidiaries			Total shareholders’ equity
	Common Stock			Additional paid-in capital			Accumulated deficit			Treasury Stock
	Shares	Amount								Shares	Amount
Balance at January 1, 2017	99,519	$	995	$	1,325,481		$	(636,351	)	6	$	—		$	690,125		$	1,320		$	691,445
Issuance of common stock pursuant to employee stock compensation plan	499	5		(5		)	—			—	—			—			—			—
Common stock issued to Board members and advisors	55	1		(1		)	—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		12,521			—			—	—			12,521			—			12,521
Stock options exercised, net of options forfeited in net share settlements	327	3		(27		)	—			—	—			(24		)	—			(24		)
Restricted stock forfeited	—	—		—			—			69	(745		)	(745		)	—			(745		)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	—	—		(1,250		)	—			—	—			(1,250		)	(1,403		)	(2,653		)
Contributions related to formation of Joint Venture (see Note 3)	—	—		116,622			—			—	—			116,622			54,878			171,500
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—			—			—	—			—			14,700			14,700
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—			—			—	—			—			(1,960		)	(1,960		)
Current period net income	—	—		—			72,493			—	—			72,493			5,094			77,587
Balance at June 30, 2017	100,400	$	1,004	$	1,453,341		$	(563,858	)	75	$	(745	)	$	889,742		$	72,629		$	962,371

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

5

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED

(In thousands)

	Six Months Ended   June 30,
	2017			2016
Operating activities
Net income (loss)	$	77,587		$	(213,414	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(33,821		)	33,464
Depletion, depreciation and amortization	75,266			60,170
Accretion of asset retirement obligations	614			552
Full-cost ceiling impairment	—			158,633
Stock-based compensation expense	11,192			5,553
Amortization of debt issuance cost	64			592
Net gain on asset sales and inventory impairment	(7		)	(2,067		)
Changes in operating assets and liabilities
Accounts receivable	(25,642		)	(2,751		)
Lease and well equipment inventory	(140		)	(514		)
Prepaid expenses	(2,619		)	186
Other assets	165			520
Accounts payable, accrued liabilities and other current liabilities	4,442			2,451
Royalties payable	11,435			153
Advances from joint interest owners	3,768			5,083
Income taxes payable	—			(2,848		)
Other long-term liabilities	(1,062		)	3,837
Net cash provided by operating activities	121,242			49,600
Investing activities
Oil and natural gas properties capital expenditures	(328,929		)	(162,381		)
Expenditures for other property and equipment	(41,743		)	(47,548		)
Proceeds from sale of assets	977			—
Restricted cash	—			43,437
Restricted cash in less-than-wholly-owned subsidiaries	(13,783		)	460
Net cash used in investing activities	(383,478		)	(166,032		)
Financing activities
Proceeds from issuance of common stock	—			142,350
Cost to issue equity	—			(768		)
Proceeds from stock options exercised	2,201			—
Contributions related to formation of Joint Venture	171,500			—
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	14,700			—
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(1,960		)	—
Taxes paid related to net share settlement of stock-based compensation	(2,970		)	(1,009		)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653		)	—
Net cash provided by financing activities	180,818			140,573
(Decrease) increase in cash	(81,418		)	24,141
Cash at beginning of period	212,884			16,732
Cash at end of period	$	131,466		$	40,873
Supplemental disclosures of cash flow information (Note 11)

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

6

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED

NOTE 1 - NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is 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. The Company’s 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

The interim unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Annual Report”) filed with the SEC. The Company consolidates certain subsidiaries and joint ventures that are less than wholly owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less than wholly owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments, consisting only of normal, recurring adjustments, which are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of June 30, 2017. Amounts as of December 31, 2016 are derived from the Company’s audited consolidated financial statements in the Annual Report.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the prior periods’ financial statements to conform to the current period presentation. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting. As a result, $0.9 million for the three months ended June 30, 2016 and $1.4 million for the six months ended June 30, 2016 were reclassified from other income to third-party midstream services revenues. In addition, $1.1 million related to midstream operating costs for the three months ended June 30, 2016 and $2.1 million for the six months ended June 30, 2016 were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For the three and six months ended June 30, 2017, the cost center ceiling was higher than the capitalized costs

7

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

of oil and natural gas properties; no impairment charge was necessary. However, due primarily to declines in oil and natural gas prices in early 2016, the capitalized costs of oil and natural gas properties exceeded the cost center ceiling for the three and six months ended June 30, 2016, and as a result, the Company recorded impairment charges to its net capitalized costs of $78.2 million and $158.6 million, respectively, in its interim unaudited condensed consolidated statements of operations.

The Company capitalized approximately $5.2 million and $4.0 million of its general and administrative costs for the three months ended June 30, 2017 and 2016, respectively, and approximately $1.9 million and $1.7 million of its interest expense for the three months ended June 30, 2017 and 2016, respectively. The Company capitalized approximately $10.8 million and $6.0 million of its general and administrative costs for the six months ended June 30, 2017 and 2016, respectively, and approximately $3.2 million and $2.2 million of its interest expense for the six months ended June 30, 2017 and 2016, respectively.

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive.

The following table sets forth the computation of diluted weighted average common shares outstanding for the three and six months ended June 30, 2017 and 2016 (in thousands).

	Three Months Ended   June 30,		Six Months Ended   June 30,
	2017	2016	2017	2016
Weighted average common shares outstanding
Basic	100,211	92,346	100,005	88,826
Dilutive effect of options and restricted stock units	16	—	450	—
Diluted weighted average common shares outstanding	100,227	92,346	100,455	88,826

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the diluted weighted average common shares outstanding for both the three and six months ended June 30, 2016, respectively, because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for both the three and six months ended June 30, 2016, respectively, as the security holders do not have the obligation to share in the losses of the Company.

Recent Accounting Pronouncements

Revenue from Contracts with Customers.In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company expects to adopt the new guidance effective January 1, 2018 using the modified approach. The Company is evaluating the new guidance, including (i) identification of revenue streams and (ii) review of contracts and procedures currently in place.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842),which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial

8

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The update should be applied using a retrospective transition method to each period presented. The Company believes that the impact of the adoption of this ASU will change the presentation of its beginning and ending cash balances on its Consolidated Statements of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing activities on its Consolidated Statements of Cash Flows.

Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted. Entities are required to apply guidance prospectively upon adoption. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

NOTE 3 – BUSINESS COMBINATION

Joint Venture

On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets. The Company retained its ownership in certain midstream assets in South Texas and Northwest Louisiana, which are not part of the Joint Venture.

The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution. The Company may earn an additional $73.5 million in performance incentives over the next five years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140.0 million in the aggregate to expand the Joint Venture’s midstream operations and asset base. The Joint Venture is consolidated in the Company’s interim unaudited condensed consolidated financial statements with Five Point’s interest in the Joint Venture being accounted for as a non-controlling interest.

In connection with the Joint Venture, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed fee natural gas processing agreement (see Note 10).

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Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 4 - ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2017 (in thousands).

Beginning asset retirement obligations	$	20,640
Liabilities incurred during period	1,222
Liabilities settled during period	(176		)
Revisions in estimated cash flows	794
Accretion expense	614
Ending asset retirement obligations	23,094
Less: current asset retirement obligations(1)	(703		)
Long-term asset retirement obligations	$	22,391

 _______________

(1) Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2017.

NOTE 5 - DEBT

At June 30, 2017 and August 2, 2017, the Company had $575.0 million of outstanding 6.875% senior notes due 2023, no borrowings outstanding under the Company’s revolving credit agreement (the “Credit Agreement”) and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

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 the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2016, and on April 28, 2017, the borrowing base was increased to $450.0 million and the maximum facility amount remained at $500.0 million. The Company elected to keep the borrowing commitment at $400.0 million. Borrowings under the Credit Agreement are limited to the least of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020.

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $1.1 million at June 30, 2017, and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company 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 to repay the deficit in equal installments over a period of six months.

The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2017.

Senior Unsecured Notes

On April 14, 2015 and December 9, 2016, the Company issued$400.0 million and $175.0 million, respectively, of 6.875% senior notes due 2023 (collectively, the “Notes”). The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April and October 15 of each year.

On May 24, 2017, and pursuant to a registered exchange offer, the Company exchanged all of the $175.0 million of Notes issued on December 9, 2016, which were privately placed, for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act of 1933, as amended. The terms of such registered Notes are substantially the same as the terms of the original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the original Notes do not apply to the registered Notes.

10

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 5 - DEBT - Continued

On February 17, 2017, in connection with the formation of San Mateo (see Note 3), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted subsidiaries under the indenture governing the Notes.

The following presents condensed consolidating financial information on an issuer (Matador), Non-Guarantor Subsidiaries, Guarantor Subsidiaries and consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheet June 30, 2017
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	385,885	$	—	$	1,679	$	(387,564	)	$	—
Third-party current assets	2,944		16,953		226,890		—			246,787
Net property and equipment	—		151,331		1,375,173		—			1,526,504
Investment in subsidiaries	1,083,542		—		75,585		(1,159,127		)	—
Third-party long-term assets	—		—		3,785		—			3,785
Total assets	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	1,679	$	385,885	$	(387,564	)	$	—
Third-party current liabilities	8,640		17,753		185,791		—			212,184
Senior unsecured notes payable	573,988		—		—		—			573,988
Other third-party long-term liabilities	—		639		27,894		—			28,533
Total equity attributable to Matador Resources Company	889,743		75,584		1,083,542		(1,159,127		)	889,742
Non-controlling interest in subsidiaries	—		72,629		—		—			72,629
Total liabilities and equity	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076

Condensed Consolidating Balance Sheet December 31, 2016
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	316,791	$	3,571	$	12,091	$	(332,453	)	$	—
Third-party current assets	101,102		4,242		173,838		—			279,182
Net property and equipment	33		113,107		1,071,385		—			1,184,525
Investment in subsidiaries	856,762		—		90,275		(947,037		)	—
Third-party long-term assets	—		—		958		—			958
Total assets	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	12,091	$	320,362	$	(332,453	)	$	—
Third-party current liabilities	9,265		16,632		143,608		—			169,505
Senior unsecured notes payable	573,924		—		—		—			573,924
Other third-party long-term liabilities	1,374		602		27,815		—			29,791
Total equity attributable to Matador Resources Company	690,125		90,275		856,762		(947,037		)	690,125
Non-controlling interest in subsidiaries	—		1,320		—		—			1,320
Total liabilities and equity	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665

11

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 5 - DEBT - Continued

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	11,274		$	127,198	$	(8,861	)	$	129,611
Total expenses	1,586			4,814			93,083		(8,861		)	90,622
Operating (loss) income	(1,586		)	6,460			34,115		—			38,989
Net gain on asset sales and inventory impairment	—			—			—		—			—
Interest expense	(9,224		)	—			—		—			(9,224		)
Other income	(27		)	26			1,923		—			1,922
Earnings in subsidiaries	39,228			—			3,244		(42,472		)	—
Income before income taxes	28,391			6,486			39,282		(42,472		)	31,687
Total income tax (benefit) provision	(118		)	64			54		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(3,178		)	—		—			(3,178		)
Net income attributable to Matador Resources Company shareholders	$	28,509		$	3,244		$	39,228	$	(42,472	)	$	28,509

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	3,210		$	44,778		$	(1,894	)	$	46,094
Total expenses	1,032			1,244			146,323			(1,894		)	146,705
Operating (loss) income	(1,032		)	1,966			(101,545		)	—			(100,611		)
Net gain on asset sales and inventory impairment	—			—			1,002			—			1,002
Interest expense	(6,167		)	—			—			—			(6,167		)
Other income	—			—			29			—			29
(Loss) earnings in subsidiaries	(98,672		)	—			1,842			96,830			—
(Loss) income before income taxes	(105,871		)	1,966			(98,672		)	96,830			(105,747		)
Total income tax (benefit) provision	(18		)	18			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(106		)	—			—			(106		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(105,853	)	$	1,842		$	(98,672	)	$	96,830		$	(105,853	)

12

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 5 - DEBT - Continued

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	20,937		$	259,846	$	(16,358	)	$	264,425
Total expenses	2,846			8,682			175,987		(16,358		)	171,157
Operating (loss) income	(2,846		)	12,255			83,859		—			93,268
Net gain on asset sales and inventory impairment	—			—			7		—			7
Interest expense	(17,679		)	—			—		—			(17,679		)
Other income	—			26			1,965		—			1,991
Earnings in subsidiaries	92,900			—			7,069		(99,969		)	—
Income before income taxes	72,375			12,281			92,900		(99,969		)	77,587
Total income tax (benefit) provision	(118		)	118			—		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(5,094		)	—		—			(5,094		)
Net income attributable to Matador Resources Company shareholders	$	72,493		$	7,069		$	92,900	$	(99,969	)	$	72,493

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	4,527		$	88,825		$	(2,635	)	$	90,717
Total expenses	2,967			2,377			290,248			(2,635		)	292,957
Operating (loss) income	(2,967		)	2,150			(201,423		)	—			(202,240		)
Net gain on asset sales and inventory impairment	—			—			2,067			—			2,067
Interest expense	(13,365		)	—			—			—			(13,365		)
Other income	—			—			124			—			124
(Loss) earnings in subsidiaries	(197,200		)	—			2,032			195,168			—
Income before income taxes	(213,532		)	2,150			(197,200		)	195,168			(213,414		)
Total income tax (benefit) provision	(25		)	25			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(93		)	—			—			(93		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(213,507	)	$	2,032		$	(197,200	)	$	195,168		$	(213,507	)

13

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 5 - DEBT - Continued

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(98,583	)	$	1,566		$	218,259		$	—		$	121,242
Net cash provided by (used in) investing activities	33			(51,580		)	(198,051		)	(133,880		)	(383,478		)
Net cash provided by (used in) financing activities	—			47,707			(769		)	133,880			180,818
(Decrease) increase in cash	(98,550		)	(2,307		)	19,439			—			(81,418		)
Cash at beginning of period	99,795			2,307			110,782			—			212,884
Cash at end of period	$	1,245		$	—		$	130,221		$	—		$	131,466

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(24,519	)	$	(6,198	)	$	80,317		$	—		$	49,600
Net cash used in investing activities	(117,086		)	(44,074		)	(172,108		)	167,236			(166,032		)
Net cash provided by financing activities	141,582			50,150			116,077			(167,236		)	140,573
(Decrease) increase in cash	(23		)	(122		)	24,286			—			24,141
Cash at beginning of period	80			186			16,466			—			16,732
Cash at end of period	$	57		$	64		$	40,752		$	—		$	40,873

NOTE 6 - INCOME TAXES

The Company’s deferred tax assets exceeded its deferred tax liabilities at June 30, 2017 due to the deferred tax assets generated by the full-cost ceiling impairment charges recorded in prior periods; as a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015. The Company retained a full valuation allowance at June 30, 2017 due to uncertainties regarding the future realization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized.

NOTE 7 - STOCK-BASED COMPENSATION

In February 2017, the Company granted awards of 228,174 shares of restricted stock and options to purchase 590,128 shares of the Company’s common stock at an exercise price of $27.26 per share to certain of its employees. The fair value of these awards was approximately $12.4 million. All of these awards vest ratably over three years. In February 2017, the Company also granted awards of 174,561 shares of restricted stock and options to purchase 444,491 shares of the Company’s common stock at an exercise price of $26.86 per share to certain of its employees. The fair value of these awards was approximately $9.3 million. All of these awards vest ratably over three years.

In June 2017, the Company granted an employee an award of 87,757 shares of common stock that vested immediately on the grant date. The fair value of this award was approximately $2.1 million. In June 2017, the Company also accelerated the expense for 97,797 restricted stock units issued to directors and outstanding prior to June 2017, resulting from a change in the vesting schedule applicable to equity awards granted to the Company’s directors. The total expense associated with these restricted stock units recognized in the three months ended June 30, 2017 was approximately $1.5 million.

14

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS

At June 30, 2017, the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2017 and 2018.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2017.

Commodity	Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)
Oil	07/01/2017 - 12/31/2017	2,460,000	$	45.17	$	55.75	$	4,365
Oil	01/01/2018 - 12/31/2018	1,920,000	$	43.91	$	63.44	4,990
Natural Gas	07/01/2017 - 12/31/2017	12,540,000	$	2.51	$	3.60	(500		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	12
Total open derivative financial instruments							$	8,867

These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its interim unaudited condensed consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets
June 30, 2017
Current assets	$	10,835		$	(3,768	)	$	7,067
Other assets	5,066			(2,074		)	2,992
Current liabilities	(4,915		)	3,723			(1,192		)
Other liabilities	(2,074		)	2,074			—
Total	$	8,912		$	(45	)	$	8,867
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

15

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the interim unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.

		Three Months Ended   June 30,						Six Months Ended   June 30,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2017			2016			2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	581		$	561		$	(1,053	)	$	6,024
Natural Gas	Revenues: Realized (loss) gain on derivatives	(23		)	1,904			(608		)	3,504
Realized gain (loss) on derivatives		558			2,465			(1,661		)	9,528
Oil	Revenues: Unrealized gain (loss) on derivatives	10,643			(19,319		)	28,422			(26,974		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	2,547			(7,306		)	5,399			(6,490		)
Unrealized gain (loss) on derivatives		13,190			(26,625		)	33,821			(33,464		)
Total		$	13,748		$	(24,160	)	$	32,160		$	(23,936	)

NOTE 9 - FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2017 and December 31, 2016 (in thousands).

	Fair Value Measurements at June 30, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil and natural gas derivatives	$	—	$	10,059		$	—	$	10,059
Oil and natural gas derivatives	—		(1,192		)	—		(1,192		)
Total	$	—	$	8,867		$	—	$	8,867

16

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 9 - FAIR VALUE MEASUREMENTS - Continued

	Fair Value Measurements at December 31, 2016 using
Description	Level 1		Level 2			Level 3		Total
Liabilities
Oil and natural gas derivatives	$	—	$	(24,954	)	$	—	$	(24,954	)
Total	$	—	$	(24,954	)	$	—	$	(24,954	)

Additional disclosures related to derivative financial instruments are provided in Note 8.

Other Fair Value Measurements

At June 30, 2017 and December 31, 2016, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities.

At June 30, 2017 and December 31, 2016, the fair value of the Notes was $592.3 million and $605.2 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Salt Water Disposal Commitments

Eagle Ford

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

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid $0.5 million and $0.8 million in processing and transportation fees under this agreement during the three months ended June 30, 2017 and 2016, respectively, and $1.0 million and $1.7 million in processing and transportation fees under this agreement during the six months ended June 30, 2017 and 2016, respectively. The future undiscounted minimum payment under this agreement as of June 30, 2017 was $0.2 million.

Delaware Basin — Loving County, Texas Natural Gas Processing

In late 2015, the Company entered into a 15-year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at June 30, 2017, the total deficiency fee required to be paid would be approximately $11.6 million. In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a

17

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 10 - COMMITMENTS AND CONTINGENCIES - Continued

contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $3.7 million and $2.8 million in natural gas processing and gathering fees under this agreement during the three months ended June 30, 2017 and 2016, respectively, and $6.8 million and $4.7 million in natural gas processing and gathering fees under this agreement during the six months ended June 30, 2017 and 2016, respectively.The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Delaware Basin — San Mateo

In connection with the Joint Venture, effective as of February 1, 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). The Joint Venture will provide the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at June 30, 2017 was approximately $256.4 million.

Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total commitments under these agreements are $56.9 million. The subsidiary of San Mateo paid approximately $7.9 million and $9.9 million under these agreements during the three and six months ended June 30, 2017. As of June 30, 2017, the remaining obligations under these agreements were $47.0 million, which are expected to be incurred within the next year.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for two years or less. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $42.0 million at June 30, 2017.

At June 30, 2017, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $19.7 million at June 30, 2017. The Company expects these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

18

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 11 - SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at June 30, 2017 and December 31, 2016 (in thousands).

	June 30, 2017		December 31, 2016
Accrued evaluated and unproved and unevaluated property costs	$	98,589	$	54,273
Accrued support equipment and facilities costs	15,596		15,139
Accrued lease operating expenses	12,613		16,009
Accrued interest on debt	8,345		6,541
Accrued asset retirement obligations	703		915
Accrued partners’ share of joint interest charges	12,479		5,572
Other	3,011		3,011
Total accrued liabilities	$	151,336	$	101,460

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2017 and 2016 (in thousands).

	Six Months Ended   June 30,
	2017			2016
Cash paid for interest expense, net of amounts capitalized	$	15,875		$	12,226
Increase in asset retirement obligations related to mineral properties	$	1,978		$	2,511
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(138	)	$	75
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	43,797		$	(3,476	)
Increase (decrease) in liabilities for support equipment and facilities	$	1,838		$	(11,565	)
Stock-based compensation expense recognized as liability	$	(339	)	$	88
(Decrease) increase in liabilities for accrued cost to issue equity	$	(343	)	$	62
Transfer of inventory from oil and natural gas properties	$	(228	)	$	474

19

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 12 - SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. As of February 17, 2017, substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 3).

The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”

	Exploration and Production							Consolidations and Eliminations			Consolidated Company
			Midstream		Corporate
Three Months Ended June 30, 2017
Oil and natural gas revenues	$	113,387	$	377	$	—		$	—		$	113,764
Midstream services revenues	—		11,367		—			(9,268		)	2,099
Realized gain on derivatives	558		—		—			—			558
Unrealized gain on derivatives	13,190		—		—			—			13,190
Expenses(1)	78,078		5,960		15,852			(9,268		)	90,622
Operating income (loss)(2)	$	49,057	$	5,784	$	(15,852	)	$	—		$	38,989
Total assets	$	1,436,678	$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	165,583	$	27,347	$	1,752		$	—		$	194,682

_____________________

(1) Includes depletion, depreciation and amortization expenses of $39.6 million and $1.3 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.4 million.

(2) Includes $3.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $13.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

20

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 12 - SEGMENT INFORMATION - Continued

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Three Months Ended June 30, 2016
Oil and natural gas revenues	$	68,864		$	472	$	—		$	—		$	69,336
Midstream services revenues	—			3,469		—			(2,551		)	918
Realized gain on derivatives	2,465			—		—			—			2,465
Unrealized loss on derivatives	(26,625		)	—		—			—			(26,625		)
Expenses(1)	134,338			1,562		13,356			(2,551		)	146,705
Operating (loss) income(2)	$	(89,634	)	$	2,379	$	(13,356	)	$	—		$	(100,611	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	97,309		$	11,192	$	2,328		$	—		$	110,829

_____________________

(1) Includes depletion, depreciation and amortization expenses of $30.6 million and $0.5 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $78.2 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.2 million.

(2) Includes $106,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2017
Oil and natural gas revenues	$	227,552		$	1,059	$	—		$	—		$	228,611
Midstream services revenues	—			20,983		—			(17,329		)	3,654
Realized loss on derivatives	(1,661		)	—		—			—			(1,661		)
Unrealized gain on derivatives	33,821			—		—			—			33,821
Expenses(1)	146,416			10,462		31,608			(17,329		)	171,157
Operating income (loss)(2)	$	113,296		$	11,580	$	(31,608	)	$	—		$	93,268
Total assets	$	1,436,678		$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	373,956		$	40,227	$	3,216		$	—		$	417,399

_____________________

(1) Includes depletion, depreciation and amortization expenses of $72.1 million and $2.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.

(2) Includes $5.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $18.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

21

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 12 - SEGMENT INFORMATION - Continued

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2016
Oil and natural gas revenues	$	112,672		$	590	$	—		$	—		$	113,262
Midstream services revenues	—			5,560		—			(4,169		)	1,391
Realized gain on derivatives	9,528			—		—			—			9,528
Unrealized loss on derivatives	(33,464		)	—		—			—			(33,464		)
Expenses(1)	267,365			3,096		26,665			(4,169		)	292,957
Operating (loss) income(2)	$	(178,629	)	$	3,054	$	(26,665	)	$	—		$	(202,240	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	162,116		$	32,250	$	3,582		$	—		$	197,948

_____________________

(1) Includes depletion, depreciation and amortization expenses of $58.9 million and $1.0 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $158.6 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.3 million.

(2) Includes $93,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our interim unaudited condensed consolidated financial statements and related notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2016 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.

For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words, although not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, the sufficiency of our cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Quarterly 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;

23

• 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 Quarterly Report or in our other filings with the SEC that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Quarterly 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 do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

Overview

We are an independent energy company founded in July 2003 and 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” or the “Joint Venture”), in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

Second Quarter and Year-to-Date Highlights

For the three months ended June 30, 2017, our total oil equivalent production was 3.4 million BOE, and our average daily oil equivalent production was 36,922 BOE per day, of which 19,423 Bbl per day, or 53%, was oil and 105.0 MMcf per day, or 47%, was natural gas. Our oil production of 1.77 million Bbl for the three months ended June 30, 2017 increased 44% year-over-year from 1.23 million Bbl for the three months ended June 30, 2016. Our natural gas production of 9.6 Bcf for the three months ended June 30, 2017 increased 21% year-over-year from 7.9 Bcf for the three months ended June 30, 2016. For the six months ended June 30, 2017, our total oil equivalent production was 6.3 million BOE, and our average daily oil equivalent production was 34,972 BOE per day, of which 18,876 Bbl per day, or 54%, was oil and 96.6 MMcf per day, or 46%, was natural gas. Our oil production of 3.4 million Bbl for the six months ended June 30, 2017 increased 50% year-over-year from 2.3 million Bbl for the six months ended June 30, 2016. Our natural gas production of 17.5 Bcf for the six months ended June 30, 2017 increased 19% year-over-year from 14.7 Bcf for the six months ended June 30, 2016.

For the second quarter of 2017, we reported net income attributable to Matador Resources Company shareholders of approximately $28.5 million, or $0.28 per diluted common share on a GAAP basis, as compared to a net loss attributable to Matador Resources Company shareholders of $105.9 million, or $1.15 per diluted common share, for the second quarter of 2016. For the second quarter of 2017, our Adjusted EBITDA attributable to Matador Resources Company shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $72.7 million, as compared to Adjusted EBITDA of $38.9 million during the second quarter of 2016. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial

24

Measures.” For more information regarding our financial results for the second quarter of 2017, see “— Results of Operations” below.

For the six months ended June 30, 2017, we reported net income attributable to Matador Resources Company shareholders of approximately $72.5 million, or $0.72 per diluted common share on a GAAP basis, as compared to a net loss attributable to Matador Resources Company shareholders of $213.5 million, or $2.40 per diluted common share, for the six months ended June 30, 2016. For the six months ended June 30, 2017, our Adjusted EBITDA, a non-GAAP financial measure, was $142.6 million, as compared to Adjusted EBITDA of $56.1 million during the six months ended June 30, 2016. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the second quarter of 2017, see “— Results of Operations” below.

During the second quarter of 2017, we continued our focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We began 2017 operating four drilling rigs in the Delaware Basin and continued to do so throughout the first quarter of 2017. In late April 2017, we added a fifth drilling rig in the Delaware Basin and expect to operate five rigs in the Delaware Basin throughout the remainder of 2017, including three rigs in our Rustler Breaks and Antelope Ridge asset areas, one rig in our Wolf and Jackson Trust asset areas and one rig in our Ranger/Arrowhead and Twin Lakes asset areas. We expect to direct over 90% of our estimated 2017 capital expenditure budget (excluding capital expenditures related to acreage, mineral and seismic data acquisitions) to drilling and completion and midstream activities in the Delaware Basin. At June 30, 2017, we had incurred approximately $241 million, or 51%, of our 2017 capital expenditure budget of between $456 and $484 million (excluding capital expenditures related to acreage, mineral and seismic data acquisitions).

In July 2017, we took delivery of a sixth drilling rig on a temporary basis for the purpose of drilling a second salt water disposal well in the Rustler Breaks asset area for San Mateo. Upon delivery of the sixth drilling rig, the salt water disposal well was not ready to spud, so at August 2, 2017, we were using this rig to drill an additional oil and natural gas well in our Rustler Breaks asset area. At August 2, 2017, we had no plans to use this sixth rig to drill additional oil and natural gas wells for the remainder of 2017.

We also finished drilling our five-well program in the Eagle Ford shale in South Texas during the second quarter of 2017. Two of these wells were completed and turned to sales in mid-June 2017. The other three wells were completed and turned to sales in early July 2017, and thus, did not contribute to second quarter 2017 production volumes. The rig used to drill these five wells was released in May 2017, and we have no additional operated drilling activities planned in the Eagle Ford shale for the remainder of 2017.

We completed and turned to sales a total of 21 gross (14.2 net) wells in the Delaware Basin during the second quarter of 2017, including 16 gross (13.5 net) operated and five gross (0.7 net) non-operated horizontal wells. In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 13 gross (8.2 net) wells during the second quarter of 2017, including nine gross (7.6 net) operated and four gross (0.6 net) non-operated wells. Of the nine gross operated wells in the Rustler Breaks asset area, five were Wolfcamp A-XY completions, one was a Wolfcamp A-Lower completion and three were Wolfcamp B-Blair completions. In addition, we began producing oil and natural gas from five gross (4.2 net) operated wells in the Wolf asset area during the second quarter of 2017, including one Wolfcamp A-XY completion and four Second Bone Spring completions. In the Ranger, Arrowhead and Twin Lakes asset areas, we began producing oil and natural gas from a total of one gross (0.1 net) non-operated well, one gross (0.7 net) operated well and one gross (1.0 net) operated well, respectively, during the second quarter of 2017. The well in the Arrowhead asset area, a Second Bone Spring completion, and the well in the Twin Lakes asset area, a Wolfcamp D completion, were the first operated horizontal wells we had tested in their respective asset areas.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production has continued to increase over the past twelve months. Our total Delaware Basin production for the second quarter of 2017 was 27,622 BOE per day, consisting of 16,645 Bbl of oil per day and 65.9 MMcf of natural gas per day, a 90% increase from production of 14,525 BOE per day, consisting of 9,789 Bbl of oil per day and 28.4 MMcf of natural gas per day, in the second quarter of 2016. The Delaware Basin contributed approximately 86% of our daily oil production and approximately 63% of our daily natural gas production in the second quarter of 2017, as compared to approximately 72% of our daily oil production and approximately 33% of our daily natural gas production in the second quarter of 2016.

During the second quarter of 2017 and through August 2, 2017, we acquired approximately 8,300 net acres in the Delaware Basin, mostly in and around our existing acreage positions, including new leasing activities, acquisitions of small interests from mineral and working interest owners in our operated wells and acreage trades or term assignments with other operators. We incurred capital expenditures of approximately $28.0 million to acquire this additional acreage throughout the Delaware Basin, as well as for new 3-D seismic data across portions of our Wolf asset area. At August 2, 2017, we held approximately 189,500 gross (108,000 net) acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in

25

the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. We plan to continue our leasing and acquisitions efforts in the Delaware Basin during the remainder of 2017 and may also continue acquiring acreage in the Eagle Ford and Haynesville shales as strategic opportunities are identified.

Estimated Proved Reserves

The following table sets forth our estimated total proved oil and natural gas reserves at June 30, 2017, December 31, 2016 and June 30, 2016. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines 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 would 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 quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total proved reserves are estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

	June 30,   2017			December 31, 2016			June 30,   2016
Estimated Proved Reserves Data: (1)(2)
Estimated proved reserves:
Oil (MBbl)(3)	74,954			56,977			52,337
Natural Gas (Bcf)(4)	356.5			292.6			258.7
Total (MBOE)(5)	134,373			105,752			95,457
Estimated proved developed reserves:
Oil (MBbl)(3)	28,454			22,604			19,913
Natural Gas (Bcf)(4)	159.7			126.8			114.4
Total (MBOE)(5)	55,075			43,731			38,978
Percent developed	41.0		%	41.4		%	40.8		%
Estimated proved undeveloped reserves:
Oil (MBbl)(3)	46,500			34,373			32,424
Natural Gas (Bcf)(4)	196.8			165.9			144.3
Total (MBOE)(5)	79,298			62,021			56,479
Standardized Measure(6) (in millions)	$	1,001.9		$	575.0		$	468.3
PV-10(7) (in millions)	$	1,086.9		$	581.5		$	473.2

_______________

(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 period from July 2016 through June 2017 were $45.42 per Bbl for oil and $3.01 per MMBtu for natural gas, for the period from January 2016 through December 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas and for the period from July 2015 through June 2016 were $39.63 per Bbl for oil and $2.24 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.

(3) One thousand barrels of oil.

(4) One billion cubic feet of natural gas.

(5) One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

26

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

(7) 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 June 30, 2017, December 31, 2016 and June 30, 2016 may be reconciled to the 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 June 30, 2017, December 31, 2016 and June 30, 2016 were $85.0 million, $6.5 million and $4.9 million, respectively.

At June 30, 2017, our estimated total proved oil and natural gas reserves were 134.4 million BOE, including 75.0 million Bbl of oil and 356.5 Bcf of natural gas, with a Standardized Measure of $1,001.9 million and a PV-10, a non-GAAP financial measure, of $1,086.9 million. At December 31, 2016, our estimated total proved oil and natural gas reserves were 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, and at June 30, 2016, our estimated total proved oil and natural gas reserves were 95.5 million BOE, including 52.3 million Bbl of oil and 258.7 Bcf of natural gas. Our proved oil reserves of 75.0 million Bbl at June 30, 2017 increased 32%, as compared to 57.0 million Bbl at December 31, 2016, and increased 43%, as compared to 52.3 million Bbl at June 30, 2016. At June 30, 2017, approximately 41% of our total proved reserves were proved developed reserves, 56% of our total proved reserves were oil and 44% of our total proved reserves were natural gas.

As a result of our drilling, completion and delineation activities in Southeast New Mexico and West Texas since 2014, our Delaware Basin oil and natural gas reserves have become a more significant component of our total oil and natural gas reserves. Our estimated Delaware Basin proved oil and natural gas reserves increased 63% from 66.2 million BOE at June 30, 2016, or 69% of our total proved oil and natural gas reserves, including 40.3 million Bbl of oil and 155.3 Bcf of natural gas, to 108.1 million BOE, or 80% of our total proved oil and natural gas reserves, including 64.9 million Bbl of oil and 259.2 Bcf of natural gas, at June 30, 2017.

There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in the Annual Report.

Critical Accounting Policies

There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.

Recent Accounting Pronouncements

See Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of recent accounting pronouncements that we believe may have an impact on our financial statements upon adoption.

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Results of Operations

Revenues

The following table summarizes our unaudited revenues and production data for the periods indicated:

	Three Months Ended   June 30,					Six Months Ended   June 30,
	2017		2016			2017			2016
Operating Data:
Revenues (in thousands):(1)
Oil	$	81,322	$	52,691		$	164,958		$	82,849
Natural gas	32,442		16,645			63,653			30,413
Total oil and natural gas revenues	113,764		69,336			228,611			113,262
Third-party midstream services revenues(2)	2,099		918			3,654			1,391
Realized gain (loss) on derivatives	558		2,465			(1,661		)	9,528
Unrealized gain (loss) on derivatives	13,190		(26,625		)	33,821			(33,464		)
Total revenues	$	129,611	$	46,094		$	264,425		$	90,717
Net Production Volumes:(1)
Oil (MBbl)(3)	1,767		1,230			3,417			2,274
Natural gas (Bcf)(4)	9.6		7.9			17.5			14.7
Total oil equivalent (MBOE)(5)	3,360		2,550			6,330			4,720
Average daily production (BOE/d)(6)	36,922		28,022			34,972			25,934
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	46.01	$	42.84		$	48.28		$	36.43
Oil, with realized derivatives (per Bbl)	$	46.34	$	43.29		$	47.97		$	39.08
Natural gas, without realized derivatives (per Mcf)	$	3.40	$	2.10		$	3.64		$	2.07
Natural gas, with realized derivatives (per Mcf)	$	3.39	$	2.34		$	3.61		$	2.31

_________________

(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues.

(2) Reclassified from other income for the three and six months ended June 30, 2016 due to the midstream segment becoming a reportable segment.

(3) One thousand barrels of oil.

(4) One billion cubic feet of natural gas.

(5) One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(6) Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Three Months Ended June 30, 2017 as Compared to Three Months Ended June 30, 2016

Oil and natural gas revenues. Our oil and natural gas revenues increased $44.4 million to $113.8 million, or 64%, for the three months ended June 30, 2017, as compared to $69.3 million for the three months ended June 30, 2016. Our oil revenues increased $28.6 million, or 54%, to $81.3 million for the three months ended June 30, 2017, as compared to $52.7 million for the three months ended June 30, 2016. The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the three months ended June 30, 2017 of $46.01 per Bbl, as compared to $42.84 per Bbl realized for the three months ended June 30, 2016, and (ii) the 44%increase in oil production to 1.77 million Bbl of oil for the three months ended June 30, 2017, or about 19,423 Bbl of oil per day, as compared to 1.23 million Bbl of oil, or about 13,516 Bbl of oil per day, for the three months ended June 30, 2016. The increase in oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $15.8 million, or 95%, to $32.4 million for the three months ended June 30, 2017, as compared to $16.6 million for the three months ended June 30, 2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the three months ended June 30, 2017 of $3.40 per Mcf, as compared to $2.10 per Mcf realized for the three months ended June 30, 2016, and (ii) the 21% increase in our natural gas production to 9.6 Bcf for the three months ended June 30, 2017, as compared to 7.9 Bcf for the three months ended June 30, 2016. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

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Third-party midstream services revenues. Our third-party midstream services revenues increased to $2.1 million, or 129%, for the three months ended June 30, 2017, as compared to $0.9 million for the three months ended June 30, 2016. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately $1.6 million for the three months ended June 30, 2017, as compared to $0.3 million for the three months ended June 30, 2016, due to (i) our natural gas gathering system and the Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) in the Rustler Breaks asset area being placed into service in the second half of 2016 and (ii) increased natural gas production in our Wolf asset area.

Realized gain on derivatives. Our realized net gain on derivatives was $0.6 million for the three months ended June 30, 2017, as compared to a realized net gain of $2.5 million for the three months ended June 30, 2016. We realized a net gain of $0.6 million from our oil derivative contracts for the three months ended June 30, 2017, resulting from oil prices below the floor prices of certain of our oil costless collar contracts. We realized net gains of $0.6 million and $1.9 million from our oil and natural gas derivative contracts, respectively, for the three months ended June 30, 2016, resulting from oil and natural gas prices below the floor prices of the majority of our oil and natural gas costless collar contracts. We realized an average gain of approximately $0.47 per Bbl hedged on all of our open oil costless collar contracts during the three months ended June 30, 2017, as compared to an average gain of $0.81 per Bbl hedged for the three months ended June 30, 2016. Our oil volumes hedged for the three months ended June 30, 2017 were 78%higher as compared to the three months ended June 30, 2016. We realized an average gain of approximately $0.65 per MMBtu hedged on all of our open natural gas costless collar contracts for the three months ended June 30, 2016. Our total natural gas volumes hedged for the three months ended June 30, 2017 were 109%higher than the total natural gas volumes hedged for the three months ended June 30, 2016.

Unrealized gain (loss) on derivatives. Our unrealized net gain on derivatives was $13.2 million for the three months ended June 30, 2017, as compared to an unrealized net loss of $26.6 million for the three months ended June 30, 2016. During the three months ended June 30, 2017, the aggregate net fair value of our open oil and natural gas derivative contracts increased to an asset of approximately $8.9 million from a liability of $4.3 million at March 31, 2017, resulting in an unrealized net gain on derivatives of $13.2 million for the three months ended June 30, 2017. During the three months ended June 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a liability of $17.2 million from an asset of $9.4 million at March 31, 2016, resulting in an unrealized loss on derivatives of $26.6 million for the three months ended June 30, 2016.

Six Months Ended June 30, 2017 as Compared to Six Months Ended June 30, 2016

Oil and natural gas revenues. Our oil and natural gas revenues increased $115.3 million to $228.6 million, or 102%, for the six months ended June 30, 2017, as compared to $113.3 million for the six months ended June 30, 2016. Our oil revenues increased $82.1 million, or 99%, to $165.0 million for the six months ended June 30, 2017, as compared to $82.8 million for the six months ended June 30, 2016. The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the six months ended June 30, 2017 of $48.28 per Bbl, as compared to $36.43 per Bbl realized for the six months ended June 30, 2016, and (ii) the 50%increase in oil production to 3.42 million Bbl of oil in the six months ended June 30, 2017, or about 18,876 Bbl of oil per day, as compared to 2.27 million Bbl of oil, or about 12,495 Bbl of oil per day, in the six months ended June 30, 2016. This increased oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $33.2 million, or 109%, to $63.7 million for the six months ended June 30, 2017, as compared to $30.4 million for the six months ended June 30, 2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the six months ended June 30, 2017 of $3.64 per Mcf, as compared to $2.07 per Mcf realized for the six months ended June 30, 2016, and (ii) the 19%increase in our natural gas production to 17.5 Bcf for the six months ended June 30, 2017, as compared to 14.7 Bcf for the six months ended June 30, 2016. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

Third-party midstream services revenues. Our third-party midstream services revenues increased to $3.7 million, or 163%, for the six months ended June 30, 2017, as compared to $1.4 million for the six months ended June 30, 2016. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately $2.8 million for the six months ended June 30, 2017, as compared to $0.7 million for the six months ended June 30, 2016, due to (i) our natural gas gathering system and the Black River Processing Plant in the Rustler Breaks asset area being placed into service in the second half of 2016 and (ii) increased natural gas production in our Wolf asset area.

Realized gain (loss) on derivatives. Our realized net loss on derivatives was $1.7 million for the six months ended June 30, 2017, as compared to a net gain of approximately $9.5 million for the six months ended June 30, 2016. We realized net losses of $1.1 million and $0.6 million from our oil and natural gas derivative contracts, respectively, for the six months ended June 30, 2017, resulting from oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts. We realized net gains of $6.0 million and $3.5 million from our oil and natural gas derivative contracts, respectively, for the six months ended June 30, 2016, resulting from oil and natural gas prices below the floor prices of the majority of our oil and natural gas costless collar contracts. We realized an average loss of approximately $0.48 per Bbl hedged on all of our open oil costless collar contracts during the six months ended June 30, 2017, as compared to an average gain of $5.11 per Bbl hedged for the six months ended June 30, 2016. Our oil volumes hedged for the three months ended June 30, 2017 were 86%higher as

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compared to the six months ended June 30, 2016. We realized an average loss of approximately $0.05 per MMBtu hedged on all of our open natural gas costless collar contracts during the six months ended June 30, 2017, as compared to an average gain of approximately $0.61 per MMBtu hedged on all of our open natural gas costless collar contracts for the six months ended June 30, 2016. Our total natural gas volumes hedged for the six months ended June 30, 2017 were 102%higher than the total natural gas volumes hedged for the six months ended June 30, 2016.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $33.8 million for the six months ended June 30, 2017, as compared to an unrealized loss of approximately $33.5 million for the six months ended June 30, 2016. During the period from December 31, 2016 through June 30, 2017, the aggregate net fair value of our open oil and natural gas derivative contracts increased from a liability of approximately $25.0 million to an asset of approximately $8.9 million, resulting in an unrealized gain on derivatives of approximately $33.8 million for the six months ended June 30, 2017. This gain is primarily attributable to the decrease in oil and natural gas futures prices during the six months ended June 30, 2017. During the period from December 31, 2015 through June 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased from an asset of approximately $16.3 million to a liability of approximately $17.2 million, resulting in an unrealized loss on derivatives of approximately $33.5 million for the six months ended June 30, 2016.

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Expenses

The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:

	Three Months Ended   June 30,						Six Months Ended   June 30,
(In thousands, except expenses per BOE)	2017			2016			2017			2016
Expenses:
Production taxes, transportation and processing	$	12,875		$	10,556		$	24,682		$	18,459
Lease operating (1)	16,040			12,183			31,797			26,695
Plant and other midstream services operating	2,942			1,061			5,283			2,088
Depletion, depreciation and amortization	41,274			31,248			75,266			60,170
Accretion of asset retirement obligations	314			289			614			552
Full-cost ceiling impairment	—			78,171			—			158,633
General and administrative	17,177			13,197			33,515			26,360
Total expenses	$	90,622		$	146,705		$	171,157		$	292,957
Operating income (loss)	$	38,989		$	(100,611	)	$	93,268		$	(202,240	)
Other income (expense):
Net gain on asset sales and inventory impairment	$	—		$	1,002		$	7		$	2,067
Interest expense	(9,224		)	(6,167		)	(17,679		)	(13,365		)
Other income (2)	1,922			29			1,991			124
Total other expense	$	(7,302	)	$	(5,136	)	$	(15,681	)	$	(11,174	)
Net income (loss)	$	31,687		$	(105,747	)	$	77,587		$	(213,414	)
Net income attributable to non-controlling interest in subsidiaries	(3,178		)	(106		)	(5,094		)	(93		)
Net income (loss) attributable to Matador Resources Company shareholders	$	28,509		$	(105,853	)	$	72,493		$	(213,507	)
Expenses per BOE:
Production taxes, transportation and processing	$	3.83		$	4.14		$	3.90		$	3.91
Lease operating (1)	$	4.77		$	4.78		$	5.02		$	5.66
Plant and other midstream services operating	$	0.88		$	0.42		$	0.83		$	0.44
Depletion, depreciation and amortization	$	12.28		$	12.25		$	11.89		$	12.75
General and administrative	$	5.11		$	5.18		$	5.29		$	5.58

_________________

(1) $1.1 million, or $0.42 per BOE, and $2.1 million, or $0.44 per BOE, was reclassified to plant and other midstream services operating expenses for the three and six months ended June 30, 2016, respectively, due to our midstream business becoming a reportable segment.

(2) $0.9 million and $1.4 million was reclassified to midstream services revenues for the three and six months ended June 30, 2016, respectively, due to our midstream business becoming a reportable segment.

Three Months Ended June 30, 2017 as Compared to Three Months Ended June 30, 2016

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased by $2.3 million to $12.9 million, or 22%, for the three months ended June 30, 2017, as compared to $10.6 million for the three months ended June 30, 2016. The increase in production taxes, transportation and processing expenses was primarily attributable to the increase in our production taxes of $3.1 million to $6.9 million for the three months ended June 30, 2017, as compared to $3.9 million for the three months ended June 30, 2016, primarily due to the 64%increase in oil and natural gas revenues for the three months ended June 30, 2017, as compared to the three months ended June 30, 2016. In addition, the production tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production becomes attributable to New Mexico, we expect to continue to experience increased production tax expenses. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to $5.9 million for the three months ended June 30, 2017, as compared to transportation and processing expenses of $6.7 million for the three months ended June 30, 2016. This decrease of $0.8 million was primarily due to the start-up in late August 2016 of the Black River Processing Plant, which processes most of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and the 34% decrease in natural gas production between the two periods in Northwest Louisiana and East Texas where our transportation and processing charges are highest on a unit-of-production basis. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 7% to $3.83 per BOE for the three months ended June 30, 2017, as

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compared to $4.14 per BOE for the three months ended June 30, 2016. On a unit‑of-production basis, these second quarter2017 expenses benefited from significantly higher total oil equivalent production, which increased 32% in the second quarter of 2017, as compared to the second quarter of 2016.

Lease operating. Our lease operating expenses increased by $3.9 million to $16.0 million, or an increase of 32%, for the three months ended June 30, 2017, as compared to $12.2 million for the three months ended June 30, 2016. Our lease operating expenses on a unit-of-production basis remained consistent at $4.77 per BOE for the three months ended June 30, 2017, as compared to $4.78 per BOE for the three months ended June 30, 2016. Our total oil equivalent production increased 32% to approximately 3.4 million BOE for the three months ended June 30, 2017 from approximately 2.6 million BOE for the three months ended June 30, 2016. The increase in lease operating expenses on an absolute basis for the three months ended June 30, 2017, as compared to the three months ended June 30, 2016, was primarily attributable to an increase in costs of services and equipment related to the increased number of wells at June 30, 2017, as compared to June 30, 2016, as a result of our increased delineation and development activities in the Delaware Basin.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased by $1.9 million to $2.9 million, an increase of 177%, for the three months ended June 30, 2017, as compared to $1.1 million for the three months ended June 30, 2016. This increase was partially attributable to the expenses associated with our salt water disposal operations of $1.5 million for the three months ended June 30, 2017, as compared to $0.7 million for the three months ended June 30, 2016, as a result of additional salt water disposal wells operating in the second quarter of 2017. Most of the remaining increase was attributable to expenses of $0.8 million associated with the Black River Processing Plant, which began operating in August 2016.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $10.0 million to $41.3 million, or an increase of 32%, for the three months ended June 30, 2017, as compared to $31.2 million for the three months ended June 30, 2016. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased slightly to $12.28 per BOE for the three months ended June 30, 2017, as compared to $12.25 per BOE for the three months ended June 30, 2016. The increase in our total depletion, depreciation and amortization expenses was primarily attributable to (i) increased well costs, largely as a result of increased well stimulation costs, since December 31, 2016, and (ii) the 32% increase in oil and natural gas production to 3.4 million BOE for the three months ended June 30, 2017, as compared to 2.6 million BOE for the three months ended June 30, 2016. The impact of the increase in well costs and oil and natural gas production on depletion, depreciation and amortization was mostly offset by higher total proved reserves of 134.4 million BOE, or an increase of 41%, at June 30, 2017, as compared to total proved reserves of 95.5 million BOE at June 30, 2016. The increase in total proved oil and natural gas reserves was primarily attributable to the continued delineation and development of our acreage in the Delaware Basin. In addition, depreciation expenses attributable to our midstream segment were approximately $1.3 million for the three months ended June 30, 2017, as compared to $0.5 million for the three months ended June 30, 2016.

Full-cost ceiling impairment. At June 30, 2017, we recorded no impairment charge to the net capitalized costs of our oil and natural gas properties. We recorded an impairment charge of $78.2 million to the net capitalized costs of our oil and natural gas properties for the three months ended June 30, 2016.

General and administrative. Our general and administrative expenses increased $4.0 million to $17.2 million, an increase of 30%, for the three months ended June 30, 2017, as compared to $13.2 million for the three months ended June 30, 2016. The increase in our general and administrative expenses was attributable to the $3.7 million increase in non-cash stock-based compensation expense to $7.0 million for the three months ended June 30, 2017, as compared to $3.3 million for the three months ended June 30, 2016. The increase in our general and administrative expenses was also attributable to increased payroll expenses of approximately $1.4 million associated with additional employees joining the Company to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the Company. The increase in our non-cash stock-based compensation was attributable to the increased expense related to the continued vesting of awards granted from 2013 through 2017 and the granting of new awards during the second quarter of 2017, as well as a change in the vesting schedule applicable to equity awards granted to our board of directors resulting in a $1.5 million one-time stock-based compensation expense. These increases were partially offset by the increase in capitalized general and administrative expense of $1.3 million due to our increased delineation and development activities in the Delaware Basin for the three months ended June 30, 2017, as compared to the three months ended June 30, 2016. As a result, our general and administrative expenses decreased 1% on a unit-of-production basis to $5.11 per BOE for the three months ended June 30, 2017, as compared to $5.18 per BOE for the three months ended June 30, 2016.

Interest expense. For the three months ended June 30, 2017, we incurred total interest expense of approximately $11.1 million. We capitalized approximately $1.9 million of our interest expense on certain qualifying projects for the three months ended June 30, 2017 and expensed the remaining $9.2 million to operations. For the three months ended June 30, 2016, we incurred total interest expense of approximately $7.9 million. We capitalized $1.7 million of our interest expense on certain qualifying projects for the three months ended June 30, 2016 and expensed the remaining $6.2 million to operations. The increase in total interest expense of $3.3 million for the three months ended June 30, 2017, as compared to the three months ended June 30,

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2016, was attributable to an increase in the average debt outstanding. At June 30, 2017, we had no borrowings outstanding and $0.8 million in letters of credit outstanding under our revolving credit agreement (the “Credit Agreement”) and $575.0 million in outstanding senior notes. At June 30, 2016, we had no borrowings outstanding and $0.6 million in letters of credit outstanding under our Credit Agreement and $400.0 million in outstanding senior notes.

Total income tax benefit. Our deferred tax assets exceeded our deferred tax liabilities at June 30, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at June 30, 2017 due to uncertainties regarding the future realization of our deferred tax assets.

Six Months Ended June 30, 2017 as Compared to Six Months Ended June 30, 2016

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased by approximately $6.2 million to $24.7 million, or 34%, for the six months ended June 30, 2017, as compared to $18.5 million for the six months ended June 30, 2016. On a unit-of-production basis, our production taxes, transportation and processing expenses remained consistent at $3.90 per BOE for the six months ended June 30, 2017, as compared to $3.91 per BOE for the six months ended June 30, 2016. The increase in production taxes, transportation and processing expenses was primarily attributable to the $8.0 millionincrease in our production taxes to $14.1 million for the six months ended June 30, 2017, as compared to $6.1 million for the six months ended June 30, 2016, primarily due to the $115.3 millionincrease in oil and natural gas revenues for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. In addition, the production tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production becomes attributable to New Mexico, we expect to continue to experience increased production tax expenses. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to $10.6 million for the six months ended June 30, 2017, as compared to transportation and processing expenses of $12.4 million for the six months ended June 30, 2016. This decrease of $1.8 million was primarily due to the start-up in late August 2016 of the Black River Processing Plant, which processes most of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and the 36% decrease in natural gas production between the two periods in Northwest Louisiana and East Texas where our transportation and processing charges are highest on a unit-of-production basis. On a unit-of-production basis, the expenses for the six months ended June 30, 2017 also benefited from significantly higher total oil equivalent production, which increased 34% in the six months ended June 30, 2017, as compared to the six months ended June 30, 2016.

Lease operating. Our lease operating expenses increased by $5.1 million to $31.8 million, or 19%, for the six months ended June 30, 2017, as compared to $26.7 million for the six months ended June 30, 2016. Our lease operating expenses unit-of-production basis decreased 11% to $5.02 per BOE for the six months ended June 30, 2017, as compared to $5.66 per BOE for the six months ended June 30, 2016. The decrease achieved in lease operating expenses on a unit-of-production basis was attributable to several key factors, including (i) decreased costs associated with our Eagle Ford operations, including workover, salt water disposal and chemical costs, (ii) additional salt water disposal and gathering capacity added in both the Wolf and Rustler Breaks asset areas and (iii) increased oil equivalent production as compared to the six months ended June 30, 2016. This decrease was partially offset by increased workover expenses in the Wolf asset area during the six months ended June 30, 2017.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased by $3.2 million to $5.3 million, an increase of 153%, for the six months ended June 30, 2017, as compared to $2.1 million for the six months ended June 30, 2016. This increase was partially attributable to the expenses associated with our salt water disposal operations of $3.0 million for the six months ended June 30, 2017, as compared to $1.6 million for the six months ended June 30, 2016, as a result of additional salt water disposal wells operating in the second quarter of 2017. The remaining increase was attributable to expenses of $1.8 million associated with the Black River Processing Plant, which began operating in August 2016.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $15.1 million to $75.3 million, or 25%, for the six months ended June 30, 2017, as compared to $60.2 million for the six months ended June 30, 2016. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 7% to $11.89 per BOE for the six months ended June 30, 2017, as compared to $12.75 per BOE for the six months ended June 30, 2016. The increase in our total depletion, depreciation and amortization expenses was primarily attributable to (i) increased well costs, largely as a result of increased well stimulation costs, since December 31, 2016, and (ii) the 34% increase in oil and natural gas production to 6.3 million BOE for the six months ended June 30, 2017, as compared to 4.7 million BOE for the six months ended June 30, 2016. The decrease in our depletion, depreciation and amortization expenses on a unit-of-production basis was attributable to (i) the impairment charges recorded in 2016 and (ii) higher total proved reserves of 134.4 million BOE, or an increase of 41%, at June 30, 2017, as compared to total proved reserves of 95.5 million BOE at June 30, 2016. The increase in total proved oil and natural gas reserves was primarily attributable to the continued delineation and development of our acreage in the Delaware Basin. In addition, depreciation expenses attributable to our midstream segment were approximately $2.5 million for the six months ended June 30, 2017, as compared to $1.0 million for the six months ended June 30, 2016.

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Full-cost ceiling impairment. At June 30, 2017, we recorded no impairment charge to the net capitalized costs of our oil and natural gas properties. We recorded an impairment charge of $158.6 million to the net capitalized costs of our oil and natural gas properties for the six months ended June 30, 2016.

General and administrative. Our general and administrative expenses increased $7.2 million to $33.5 million, an increase of 27%, for the six months ended June 30, 2017, as compared to $26.4 million for the six months ended June 30, 2016. The increase in our general and administrative expenses was attributable to the $5.6 million increase in non-cash stock-based compensation expense to $11.2 million for the six months ended June 30, 2017, as compared to $5.6 million for the six months ended June 30, 2016. The increase in our non-cash stock-based compensation was attributable to the increased expense related to the vesting of awards granted from 2013 through 2017 and the granting of new awards during the second quarter of 2017, as well as a change in the vesting schedule applicable to equity awards granted to our board of directors resulting in a $1.5 million one-time stock-based compensation expense. The increase in our general and administrative expenses was also attributable to transaction costs of approximately $3.5 million related to the formation of San Mateo and increased payroll expenses of approximately $4.0 million associated with additional employees joining the Company to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the Company. These increases were partially offset by the increase in capitalized general and administrative expenses of $4.9 million due to our increased delineation and development activities in the Delaware Basin for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. Our general and administrative expenses decreased 5% on a unit-of-production basis to $5.29 per BOE for the six months ended June 30, 2017, as compared to $5.58 per BOE for the six months ended June 30, 2016, primarily due to our increased total oil equivalent production.

Interest expense. For the six months ended June 30, 2017, we incurred total interest expense of approximately $20.8 million. We capitalized approximately $3.2 million of our interest expense on certain qualifying projects for the six months ended June 30, 2017 and expensed the remaining $17.7 million to operations. For the six months ended June 30, 2016, we incurred total interest expense of approximately $15.6 million. We capitalized $2.2 million of our interest expense on certain qualifying projects for the six months ended June 30, 2016 and expensed the remaining $13.4 million to operations. The increase in total interest expense of $5.3 million for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, was attributable to an increase in the average debt outstanding. At June 30, 2017, we had no borrowings outstanding and $0.8 million in letters of credit outstanding under our Credit Agreement and $575.0 million in outstanding senior notes. At June 30, 2016, we had no borrowings outstanding and $0.6 million in letters of credit outstanding under our Credit Agreement and $400.0 million in outstanding senior notes.

Total income tax benefit. Our deferred tax assets exceeded our deferred tax liabilities at June 30, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at June 30, 2017 due to uncertainties regarding the future realization of our deferred tax assets.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of 2017 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditure requirements through the remainder of 2017 with a combination of cash on hand (including proceeds we received in connection with the formation of the Joint Venture), operating cash flows and borrowings under our Credit Agreement (assuming availability under our borrowing base). We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows.

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point to operate and expand our Delaware Basin midstream assets. We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Basin midstream assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2017. We operated five contracted drilling rigs in the Delaware Basin and one contracted drilling rig in the Eagle Ford during the second quarter of 2017. Our 2017 estimated capital expenditure budget consists of $400 to $420 million for drilling, completions, facilities and infrastructure and $56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017 capital expenditure budget of $110 to $125 million for San Mateo. We

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have allocated substantially all of our estimated 2017 capital expenditures to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford (including the five wells drilled and completed in 2017) and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. For the remainder of 2017, our Delaware Basin drilling program will continue to focus on the development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead, Antelope Ridge and Twin Lakes asset areas, although we may also continue to delineate previously untested zones in the Wolf and Rustler Breaks asset areas.

During the second quarter of 2017 and through August 2, 2017, we acquired approximately 8,300 net acres in the Delaware Basin, mostly in and around our existing acreage positions, including new leasing activities, acquisitions of small interests from mineral and working interest owners in our operated wells and acreage trades or term assignments with other operators. We incurred capital expenditures of approximately $28.0 million to acquire this additional acreage throughout the Delaware Basin, as well as for new 3-D seismic data across portions of our Wolf asset area. At August 2, 2017, we held approximately 189,500 gross (108,000 net) acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas.

We plan to continue our leasing and acquisitions efforts in the Delaware Basin during the remainder of 2017 and may also continue acquiring acreage in the Eagle Ford and Haynesville shales. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the opportunity. As a result, it is difficult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for the remainder of 2017.

At June 30, 2017, we had cash totaling approximately $131.5 million and restricted cash totaling approximately $15.0 million, most of which is associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. Additionally, at June 30, 2017, we had no outstanding borrowings under our Credit Agreement, which has a borrowing base of $450.0 million and an elected commitment of $400.0 million.

Our 2017 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, including the expansion of the Black River Processing Plant, the ability of our Joint Venture partner to meet its capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for the remainder of 2017 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for the remainder of 2017 and the hedges we currently have in place. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. As of August 2, 2017, we had approximately 65% of our anticipated oil production and approximately 70% of our anticipated natural gas production hedged for the remainder of 2017. See Note 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at June 30, 2017.

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Our unaudited cash flows for the six months ended June 30, 2017 and 2016 are presented below:

	Six Months Ended   June 30,
(In thousands)	2017			2016
Net cash provided by operating activities	$	121,242		$	49,600
Net cash used in investing activities	(383,478		)	(166,032		)
Net cash provided by financing activities	180,818			140,573
Net change in cash	$	(81,418	)	$	24,141
Adjusted EBITDA(1) attributable to Matador Resources Company shareholders	$	142,611		$	56,145

__________________

(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Non-GAAP Financial Measures” below.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased $71.6 million to $121.2 million for the six months ended June 30, 2017 from $49.6 million for the six months ended June 30, 2016. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $130.9 million for the six months ended June 30, 2017 from $43.5 million for the six months ended June 30, 2016. This increase was primarily attributable to higher oil and natural gas production and higher commodity prices and was partially offset by the decrease in our realized gains on derivatives and an increase in certain expenses. Changes in our operating assets and liabilities between the two periods resulted in a net decrease of approximately $15.8 million in net cash provided by operating activities for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements where possible in order to minimize ongoing future commitments.

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $217.4 million to $383.5 million for the six months ended June 30, 2017 from $166.0 million for the six months ended June 30, 2016. This increase in net cash used in investing activities is primarily due to an increase of $166.5 million in oil and natural gas properties capital expenditures for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. Cash used for oil and natural gas properties capital expenditures for the six months ended June 30, 2017 was primarily attributable to the acquisition of additional leasehold and mineral interests and our operated drilling and completion activities in the Delaware Basin. A small portion of our capital expenditures for the six months ended June 30, 2017 was directed to our participation in non-operated wells and our operated drilling and completion activities in the Eagle Ford shale. Additionally, there was an increase in cash outflows related to restricted cash of approximately $57.7 million between the two periods. These increases were partially offset by a decrease in cash used for other property and equipment of approximately $5.8 million.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities increased by $40.2 million to $180.8 million for the six months ended June 30, 2017 from $140.6 million for the six months ended June 30, 2016. The increase in net cash provided by financing activities for the six months ended June 30, 2017 was primarily attributable to (i) the increase of $171.5 million related to contributions from the formation of the Joint Venture and (ii) the net increase of $12.7 million related to contributions from and distributions to the non-controlling interest owners of less-than-wholly-owned subsidiaries, which were offset by (x) an increase in cash outflows of $2.7 million related to the purchase of the non-controlling interest of a less-than-wholly-owned subsidiary and (y) an increase in cash outflows of $2.0 million related to taxes paid in connection with the net share settlement of stock-based compensation. The net cash provided by financing activities for the six months ended June 30, 2016 was primarily attributable to the net proceeds from our March 2016 equity offering of $142.4 million ($141.6 million including cost to issue equity).

See Note 5 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our debt, including our Credit Agreement and the senior notes.

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Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

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The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

	Three Months Ended   June 30,						Six Months Ended   June 30,
(In thousands)	2017			2016			2017			2016
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders	$	28,509		$	(105,853	)	$	72,493		$	(213,507	)
Net income attributable to non-controlling interest in subsidiaries	3,178			106			5,094			93
Net income (loss)	31,687			(105,747		)	77,587			(213,414		)
Interest expense	9,224			6,167			17,679			13,365
Depletion, depreciation and amortization	41,274			31,248			75,266			60,170
Accretion of asset retirement obligations	314			289			614			552
Full-cost ceiling impairment	—			78,171			—			158,633
Unrealized (gain) loss on derivatives	(13,190		)	26,625			(33,821		)	33,464
Stock-based compensation expense	7,026			3,310			11,192			5,553
Net gain on asset sales and inventory impairment	—			(1,002		)	(7		)	(2,067		)
Consolidated Adjusted EBITDA	76,335			39,061			148,510			56,256
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(3,683		)	(115		)	(5,899		)	(111		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	72,652		$	38,946		$	142,611		$	56,145

	Three Months Ended June 30,						Six Months Ended   June 30,
(In thousands)	2017			2016			2017			2016
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	59,933		$	31,242		$	121,242		$	49,600
Net change in operating assets and liabilities	7,198			1,944			9,653			(6,117		)
Interest expense, net of non-cash portion	9,204			5,875			17,615			12,773
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(3,683		)	(115		)	(5,899		)	(111		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	72,652		$	38,946		$	142,611		$	56,145

The net income attributable to Matador Resources Company shareholders increased by $134.4 million to $28.5 million for the three months ended June 30, 2017, as compared to a net loss attributable to Matador Resources Company shareholders of $105.9 million for the three months ended June 30, 2016. This increase in net income attributable to Matador Resources Company shareholders for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 is primarily attributable to (i) the decrease of $78.2 million in the full-cost ceiling impairment, (ii) the increase in oil and natural gas revenues of $44.4 million and (iii) a change of $39.8 million from unrealized loss to unrealized gain on derivatives, offset by (x) the increase in certain expenses, including a $10.0 million increase in depletion, depreciation and amortization expenses, (y) a $3.1 million increase in interest expense and (z) a $3.7 million increase in stock-based compensation expense.

The net income attributable to Matador Resources Company shareholders increased by $286.0 million to $72.5 million for the six months ended June 30, 2017, as compared to a net loss attributable to Matador Resources Company shareholders of $213.5 million for the six months ended June 30, 2016. This increase in net income attributable to Matador Resources Company shareholders for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 is primarily attributable to (i) the decrease of $158.6 million in the full-cost ceiling impairment, (ii) the increase in oil and natural gas revenues of $115.3 million and (iii) a change of $67.3 million from unrealized loss to unrealized gain on derivatives, offset by (x) the increase in certain expenses, including a $15.1 million increase in depletion, depreciation and amortization expenses, (y) a $4.3 million increase in interest expense and (z) a $5.6 million increase in stock-based compensation expense.

Our Adjusted EBITDA increased by $33.7 million to $72.7 million for the three months ended June 30, 2017, as compared to $38.9 million for the three months ended June 30, 2016. This increase in our Adjusted EBITDA is primarily

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attributable to higher oil and natural gas production and higher commodity prices, which were partially offset by a decrease in the realized gain on derivatives and an increase in certain expenses for the three months ended June 30, 2017, as compared to the three months ended June 30, 2016.

Our Adjusted EBITDA increased by $86.5 million to $142.6 million for the six months ended June 30, 2017, as compared to $56.1 million for the six months ended June 30, 2016. This increase in our Adjusted EBITDA is primarily attributable to higher oil and natural gas production and higher commodity prices, which were partially offset by a decrease in the realized gain on derivatives and an increase in certain expenses for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2017, the material off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation, gathering, processing, disposal and fractionation commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

Obligations and Commitments

We had the following material contractual obligations and commitments at June 30, 2017:

	Payments Due by Period
(In thousands)	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
Contractual Obligations:
Revolving credit borrowings, including letters of credit(1)	$	821	$	—	$	—	$	821	$	—
Senior unsecured notes(2)	575,000		—		—		—		575,000
Office leases	23,864		2,494		5,051		5,314		11,005
Non-operated drilling commitments(3)	19,697		19,697		—		—		—
Drilling rig contracts(4)	41,974		27,295		14,679		—		—
Asset retirement obligations	23,094		703		572		3,737		18,082
Gas processing agreements with non-affiliates(5)	11,858		3,795		8,063		—		—
Gathering, processing and disposal agreements with San Mateo(6)	256,412		—		36,110		69,994		150,308
Natural gas plant engineering, procurement, construction and installation contract(7)	47,026		47,026		—		—		—
Total contractual cash obligations	$	999,746	$	101,010	$	64,475	$	79,866	$	754,395

__________________

(1) At June 30, 2017, we had no borrowings outstanding under our Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020.

(2) The amounts included in the table above represent principal maturities only.

(3) At June 30, 2017, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at June 30, 2017. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $19.7 million at June 30, 2017, which we expect to incur within the next year.

(4) We do not own or operate our own drilling rigs, but instead enter into contracts with third parties for such drilling rigs. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.

(5) Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a

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significant portion of our operated natural gas production in Loving County, Texas. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.

(6) Effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.

(7) Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our contractual commitments.

General Outlook and Trends

For the three months ended June 30, 2017, oil prices averaged $48.15 per Bbl, ranging from a high of $53.40 per Bbl in mid-April to a low of $42.53 per Bbl in late June, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized an average oil price of $46.01 per Bbl ($46.34 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended June 30, 2017, as compared to $42.84 per Bbl ($43.29 per Bbl including realized gains from oil derivatives) for the three months ended June 30, 2016. At August 2, 2017, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had increased from the weighted average price for the second quarter of 2017, settling at $49.59 per Bbl, which was also an increase as compared to $39.51 per Bbl at August 2, 2016.

For the three months ended June 30, 2017, natural gas prices averaged $3.14 per MMBtu, ranging from a high of approximately $3.42 per MMBtu in mid-May to a low of approximately $2.89 per MMBtu in late June, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $3.40 per Mcf ($3.39 per Mcf including realized losses from natural gas derivatives) for our natural gas production (including revenues attributable to natural gas liquids) for the three months ended June 30, 2017, as compared to $2.10 per Mcf ($2.34 per Mcf including realized gains from natural gas derivatives) for the three months ended June 30, 2016. At August 2, 2017, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had decreased from the weighted average price for the second quarter of 2017, settling at $2.81 per MMBtu, which was a small increase as compared to $2.73 per MMBtu at August 2, 2016.

The prices we receive for oil, natural gas and natural gas liquids heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or natural gas liquids prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and natural gas liquids we can produce economically. We are uncertain if oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease again in future periods.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets.

Coinciding with the recent improvements in oil and natural gas prices since the latter part of 2016, we have begun to experience price increases from our service providers for some of the products and services we use in our drilling, completion and production operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they increase further, we could experience additional price increases for drilling, completion and production products and services, although we can provide no estimates as to the eventual magnitude of these increases.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids price declines, however, drilling certain oil or natural gas wells may not be economical, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement.

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

40

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, 2016, which are disclosed in Part II, Item 7A of the Annual Report and incorporated herein by reference.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production.

We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At June 30, 2017, Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. See Note 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at June 30, 2017. Such information is incorporated herein by reference.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2017 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2017, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.

41

Part II—OTHER INFORMATION

Item 1. Legal Proceedings

We are party to several lawsuits encountered in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on our financial condition, results of operations or cash flows.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see “Item 1A. Risk Factors” in the Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the quarter ended June 30, 2017, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
April 1, 2017 to April 30, 2017	2,225	$	23.71	—	—
May 1, 2017 to May 31, 2017	2,530	22.84		—	—
June 1, 2017 to June 30, 2017	109	21.74		—	—
Total	4,864	$	23.21	—	—

_________________

(1) The shares were not re-acquired pursuant to any repurchase plan or program.

Item 6. Exhibits

A list of exhibits filed herewith is contained in the Exhibit Index that immediately precedes such exhibits and is incorporated by reference herein.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		MATADOR RESOURCES COMPANY
Date: August 7, 2017	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer

Date: August 7, 2017	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President and Chief Financial Officer

43

EXHIBIT INDEX

Exhibit Number	Description
3.1	Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011).
3.2	Amended and Restated Certificate of Formation of Matador Resources Company (filed herewith).
3.3	Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (filed herewith).
3.4	Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (filed herewith).
3.5	Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 23, 2016).
3.6	Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015).
10.1	Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.2	Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017).
10.3	Form of Restricted Stock Unit Award Agreement for Annual Grants relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (filed herewith).
10.4	Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (filed herewith).
23.1	Consent of Netherland, Sewell & Associates, Inc. (filed herewith).
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
99.1	Audit report of Netherland, Sewell & Associates, Inc. (filed herewith).
101	The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets - Unaudited, (ii) the Condensed Consolidated Statements of Operations - Unaudited, (iii) the Condensed Consolidated Statement of Changes in Shareholders’ Equity - Unaudited, (iv) the Condensed Consolidated Statements of Cash Flows - Unaudited and (v) the Notes to Condensed Consolidated Financial Statements - Unaudited (submitted electronically herewith).

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EX-3.2

Exhibit 3.2

AMENDED AND RESTATED CERTIFICATE OF FORMATION

OF

MATADOR RESOURCES COMPANY

The undersigned hereby certifies that:

ONE: The name of the corporation is Matador Resources Company (the “Corporation”). The Corporation filed its original Certificate of Formation with the Secretary of State of the State of Texas on November 22, 2010 under the name “Matador Holdco, Inc.” The Corporation filed a Certificate of Amendment to the Certificate of Formation with the Secretary of State of the State of Texas on August 2, 2011, to amend Article IX of the Certificate of Formation. The Corporation filed a Certificate of Amendment to the Certificate of Formation with the Secretary of State of the State of Texas on August 8, 2011, to change the Corporation’s name to “Matador Resources Company.”

TWO: This Amended and Restated Certificate of Formation amends the original Certificate of Formation, as such has from time to time been amended (the “Current Certificate”) and all amendments made herein are in compliance with the Texas Business Organizations Code (the “TBOC”). This Amended and Restated Certificate of Formation shall become effective on Tuesday, February 7, 2012, at 1:00 Central Standard Time.

THREE: Each amendment herein has been properly approved in the manner prescribed by Sections 21.052 through 21.055 of the TBOC and by the Corporation’s governing documents.

FOUR: The following alterations have been made to the Current Certificate in this Amended and Restated Certificate of Formation:

(1) ARTICLE I of the Current Certificate is hereby amended to delete the defined term “Corporation.”

(2) ARTICLE III of the Current Certificate is hereby amended to delete the defined term “TBOC.”

(3) ARTICLE V of the Current Certificate is hereby amended to capitalize the term “Board of Directors.”

(4) ARTICLE IV and ARTICLE VII of the Current Certificate are wholly amended as set forth in ARTICLE IV and ARTICLE VII of this Amended and Restated Certificate of Formation.

(5) ARTICLE IX of the Current Certificate is hereby amended to change the number of directors from seven to eight and to list the names and addresses of the current directors of the Corporation, which as amended and restated shall read as follows:

“ARTICLE IX

The number of directors shall be set at eight (8) until changed in the manner provided in the bylaws of the Corporation, except that no such change shall shorten the term of an incumbent director. Beginning with the 2011 annual meeting, the directors shall be classified with respect to the time for which they severally hold office into three (3) classes, as nearly equal in number as possible as determined by the Board of Directors, one class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2012, another class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2013, and another class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2014, with each member of each class to hold office until his successor is elected and qualified, until his death or retirement or until he shall resign or be removed in the manner provided in the bylaws. In any such event, such director’s successor shall become a member of the same class of directors as his predecessor. Beginning with the annual meeting to be held in 2012, the directors elected at an annual meeting shall hold office until the third succeeding annual meeting after such election.

The names and addresses of the current directors of the Corporation are:

1

Name	Address
Joseph Wm. Foran	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Charles L. Gummer	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Stephen A. Holditch	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
David M. Laney	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Gregory E. Mitchell	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Steven W. Ohnimus	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Michael C. Ryan	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Margaret B. Shannon	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240;”

(6) ARTICLE XII is deleted in its entirety.

FIVE: This Amended and Restated Certificate of Formation accurately states the text of the Current Certificate, as further amended by this Amended and Restated Certificate of Formation.

SIX: This Amended and Restated Certificate of Formation does not contain any other change in the Current Certificate other than omissions allowed by Section 3.059 of the TBOC.

SEVEN: The Certificate of Formation of the Corporation is hereby amended and restated to read in its entirety as follows:

ARTICLE I

The name of the Corporation is Matador Resources Company.

2

ARTICLE II

The Corporation is a for-profit corporation.

ARTICLE III

The purpose for which the Corporation is organized is the transaction of any or all lawful business for which for-profit corporations may be incorporated under the TBOC.

ARTICLE IV

1. Classes of Stock and Authorized Shares. The Corporation is authorized to issue two classes of stock which shall be designated, respectively, “Common Stock” and “Preferred Stock.” The aggregate number of shares of all classes of stock which the Corporation shall have authority to issue is eighty-two million (82,000,000), consisting of (a) eighty million (80,000,000) shares of Common Stock having a par value of $0.01 per share (“Common Stock”), and (b) two million (2,000,000) shares of Preferred Stock, par value $0.01 per share (“Preferred Stock”).

2. Preferred Stock. The Board of Directors is hereby expressly authorized, by resolution or resolutions from time to time adopted, to provide, out of the unissued shares of Preferred Stock, for the issuance of series of Preferred Stock. Before any shares of any such series are issued, the Board of Directors shall fix and determine, and hereby is expressly empowered to fix and determine, by resolution or resolutions, the designations, preferences, limitations and relative rights, including voting rights, of the shares of each such series, including but not limited to any of the following:

(a) the designation of such series, the number of shares to constitute such series and the stated value thereof if different from the par value thereof;

(b) whether the shares of such series shall have voting rights, in addition to any voting rights provided by law, and, if so, the terms of such voting rights, which may be full or limited;

(c) the dividends, if any, payable on such series and at what rates, whether any such dividends shall be cumulative, and, if so, from what dates, the conditions and dates upon which such dividends shall be payable, the preference or relation which such dividends shall bear to the dividends payable on any shares of stock of any other class or any other series of this class;

(d) whether the shares of such series shall be subject to redemption by the Corporation, and, if so, prices and other terms and conditions of such redemption;

(e) the amount or amounts payable upon shares of such series upon, and the rights of the holders of such series in, the voluntary or involuntary liquidation, dissolution or winding up of, or upon any distribution of the assets of, the Corporation;

(f) whether the shares of such series shall be subject to the operation of a retirement or sinking fund and, if so, the extent to and manner in which any such retirement or sinking fund shall be applied to the purchase or redemption of the shares of such series for retirement or other corporate purposes and other terms and provisions relative to the operation thereof;

(g) whether the shares of such series shall be convertible into, or exchangeable for, shares of stock of any other class or any other series of this class or any other class or classes of securities and, if so, the price or prices or the rate or rates of conversion or exchange and the method, if any, of adjusting the same, and any other terms and conditions of conversion or exchange;

(h) the limitations and restrictions, if any, to be effective while any shares of such series are outstanding upon the payment of dividends or the taking of other distributions on, and upon the purchase, redemption or other acquisition by the Corporation of, the Common Stock or shares of stock of any other class or any other series of this class;

(i) the conditions or restrictions, if any, upon the creation of indebtedness of the Corporation or upon the issue of any additional stock, including additional shares of such series or any other series of this class or of any other class; and

(j) any other powers, preferences and relative, participating, optional and other special rights and any qualifications, limitations and restrictions thereof.

The designations, preferences, limitations and relative rights of each series of Preferred Stock may differ from those of any and all other series at any time outstanding. All shares of any one series of Preferred Stock shall be identical in all respects with all other shares of such series, except that shares of any one series issued at different times may differ as to the date from which dividends thereof shall be cumulative.

ARTICLE V

No holder of any shares of capital stock of the Corporation shall be entitled as a matter of right, preemptive or otherwise, to subscribe for or purchase any class of stock of the Corporation, now or hereafter authorized to be issued, or class of stock

3

held in the treasury of the Corporation, whether issued or sold for cash or other consideration or as a dividend or otherwise. Any such class of stock may be issued or disposed of by the Board of Directors to such persons and on such terms as in its discretion it shall deem advisable.

ARTICLE VI

No shareholder of the Corporation shall have the right of cumulative voting at any election of directors or upon any other matter.

ARTICLE VII

A special meeting of the shareholders of the Corporation may be called by the holders of at least 25 percent of the shares entitled to vote at the proposed special meeting.

ARTICLE VIII

The address of the Corporation’s registered office is 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240 and the name of its registered agent at such address is Joseph Wm. Foran.

ARTICLE IX

The number of directors shall be set at eight (8) until changed in the manner provided in the bylaws of the Corporation, except that no such change shall shorten the term of an incumbent director. Beginning with the 2011 annual meeting, the directors shall be classified with respect to the time for which they severally hold office into three (3) classes, as nearly equal in number as possible as determined by the Board of Directors, one class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2012, another class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2013, and another class to hold office initially for a term expiring at the annual meeting of shareholders to be held in 2014, with each member of each class to hold office until his successor is elected and qualified, until his death or retirement or until he shall resign or be removed in the manner provided in the bylaws. In any such event, such director’s successor shall become a member of the same class of directors as his predecessor. Beginning with the annual meeting to be held in 2012, the directors elected at an annual meeting shall hold office until the third succeeding annual meeting after such election.

The names and addresses of the current directors of the Corporation are:

4

Name	Address
Joseph Wm. Foran	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Charles L. Gummer	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Stephen A. Holditch	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
David M. Laney	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Gregory E. Mitchell	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Steven W. Ohnimus	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Michael C. Ryan	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240
Margaret B. Shannon	One Lincoln Centre
	5400 LBJ Freeway, Suite 1500
	Dallas, Texas 75240

ARTICLE X

A director of the Corporation shall not be liable to the Corporation or its shareholders for monetary damages for an act or omission in the director’s capacity as a director, except to the extent that the director is found liable for (i) any breach of the director’s duty of loyalty to the Corporation or its shareholders; (ii) acts or omissions not in good faith that constitute a breach of duty of the director to the Corporation or acts or omissions that involve intentional misconduct or knowing violation of law; (iii) for any transaction from which the director received an improper benefit, whether or not the benefit resulted from an action taken within the scope of the director’s office; or (iv) any act or omission for which the liability of the director is expressly provided for by an applicable statute. If the TBOC or any other applicable Texas statute hereafter is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the Corporation, in addition to the limitation on liability provided herein, shall be limited to the fullest extent permitted by such amended act. Any repeal or modification of this Article X by the shareholders of the Corporation shall be prospective only, and shall not adversely affect any limitation on the liability of a director of the Corporation existing at the time of such repeal or modification.

ARTICLE XI

The Corporation shall indemnify its directors and may indemnify its officers, employees or agents to the full extent permitted by law if any such person was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director,

5

officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding. Such right of indemnification shall not be deemed exclusive of any other rights to which such person may be entitled under any bylaw, agreement, vote of shareholders or otherwise. The Corporation shall pay or reimburse reasonable expenses incurred by a director who was, is or is threatened to be made a named defendant or respondent in a proceeding in advance of the final disposition of the proceeding and without the determination or authorization otherwise required under the TBOC after the Corporation receives the written affirmation and written undertaking of such director as set forth in Section 8.104 of the TBOC, or any successor provision.

6

IN WITNESS WHEREOF, I have hereunto set my hand, this 3^rd day of February, 2012.

/s/ Joseph Wm. Foran

Joseph Wm. Foran

Chief Executive Officer

7

EX-3.3

Exhibit 3.3

CERTIFICATE OF AMENDMENT

to the

AMENDED AND RESTATED CERTIFICATE OF FORMATION

of

MATADOR RESOURCES COMPANY

April 2, 2015

This CERTIFICATE OF AMENDMENT (this “Certificate”) is being executed and filed pursuant to the applicable provisions of the Texas Business Organizations Code (the “TBOC”).

The undersigned hereby certifies that:

ONE: The name of the filing entity is MATADOR RESOURCES COMPANY, a Texas for-profit corporation (the “Corporation”). The original date of formation of the Corporation was November 22, 2010, and the Corporation has been assigned file number 801346526.

TWO: Section 1 of Article 4 of the Amended and Restated Certificate of Formation (the “Certificate of Formation”) of the Corporation is hereby amended to increase the amount of authorized common stock, which as amended shall read in its entirety as follows:

“1.    Classes of Stock and Authorized Shares. The Corporation is authorized to issue two classes of stock which shall be designated, respectively, “Common Stock” and “Preferred Stock.” The aggregate number of shares of all classes of stock which the Corporation shall have authority to issue is one hundred twenty-two million (122,000,000), consisting of (a) one hundred twenty million (120,000,000) shares of Common Stock having a par value of $0.01 per share (“Common Stock”), and (b) two million (2,000,000) shares of Preferred Stock, par value $0.01 per share (“Preferred Stock”).”

THREE: The amendment to the Certificate of Formation has been approved in the manner required by the TBOC and by the governing documents of the Corporation.

FOUR: This document shall become effective when the document is filed by the Secretary of State of the State of Texas.

[Signature page follows]

IN WITNESS WHEREOF, the Corporation has caused this certificate to be signed as of the date first written above.

MATADOR RESOURCES COMPANY
By:	/s/ Matthew V. Hairford
	Name: Matthew V. Hairford
	Title: President

EX-3.4

Exhibit 3.4

CERTIFICATE OF AMENDMENT

to the

AMENDED AND RESTATED CERTIFICATE OF FORMATION

of

MATADOR RESOURCES COMPANY

June 1, 2017

This CERTIFICATE OF AMENDMENT (this “Certificate”) is being executed and filed pursuant to the applicable provisions of the Texas Business Organizations Code (the “TBOC”).

The undersigned hereby certifies that:

ONE: The name of the filing entity is MATADOR RESOURCES COMPANY, a Texas for-profit corporation (the “Corporation”). The original date of formation of the Corporation was November 22, 2010, and the Corporation has been assigned file number 801346526.

TWO: Section 1 of Article 4 of the Amended and Restated Certificate of Formation of the Corporation, as previously amended (the “Certificate of Formation”), is hereby amended to increase the amount of authorized common stock, which as amended hereby shall read in its entirety as follows:

“1.    Classes of Stock and Authorized Shares. The Corporation is authorized to issue two classes of stock which shall be designated, respectively, “Common Stock” and “Preferred Stock.” The aggregate number of shares of all classes of stock which the Corporation shall have authority to issue is one hundred sixty-two million (162,000,000), consisting of (a) one hundred sixty million (160,000,000) shares of Common Stock having a par value of $0.01 per share (“Common Stock”), and (b) two million (2,000,000) shares of Preferred Stock, par value $0.01 per share (“Preferred Stock”).”

THREE: The amendment to the Certificate of Formation has been approved in the manner required by the TBOC and by the governing documents of the Corporation.

FOUR: This document shall become effective when the document is filed by the Secretary of State of the State of Texas.

[Signature page follows]

IN WITNESS WHEREOF, the Corporation has caused this certificate to be signed as of the date first written above.

MATADOR RESOURCES COMPANY
By:	/s/ Craig N. Adams
	Name: Craig N. Adams
	Title: Executive Vice President

EX-10.3

Exhibit 10.3

RESTRICTED STOCK UNIT AWARD AGREEMENT

MATADOR RESOURCES COMPANY AMENDED AND RESTATED

2012 LONG-TERM INCENTIVE PLAN

1.Award of Restricted Stock Units. Pursuant to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “Plan”) for Employees, Contractors, and Outside Directors of Matador Resources Company, a Texas corporation (the “Company”), the Company grants to

[NAME]

(the “Participant”),

an Outside Director of the Company, an Award under the Plan for[NUMBER]Restricted Stock Units (the “Awarded Units”) which may be converted into the number of shares of Common Stock of the Company equal to the number of Restricted Stock Units, subject to the terms and conditions of the Plan and this Restricted Stock Unit Award Agreement (this “Agreement”). The “Date of Grant” of this Restricted Stock Unit Award is [DATE]. Each Awarded Unit shall be a notional share of Common Stock, with the value of each Awarded Unit being equal to the Fair Market Value of a share of Common Stock at any time. Capitalized terms used in this Agreement that are defined in the Plan shall have the same meanings assigned to them in the Plan.

2.Subject to Plan. This Agreement is subject to the terms and conditions of the Plan. The terms of the Plan shall control to the extent such terms are not otherwise inconsistent with the provisions of this Agreement, and the terms of the Agreement shall control to the extent such terms are inconsistent with the provisions of the Plan. This Agreement is subject to any rules promulgated pursuant to the Plan by the Board or the Committee and communicated to the Participant in writing.

3.Vesting; Time of Delivery of Shares. Awarded Units which have become vested pursuant to the terms of this Section 3 are collectively referred to herein as “Vested RSUs.” All other Awarded Units are collectively referred to herein as “Unvested RSUs.”

a.    Except as specifically provided in this Agreement and subject to certain restrictions and conditions set forth in the Plan, the Awarded Units shall be vested as follows:

One hundred percent (100%) of the total Awarded Units shall vest and become Vested RSUs immediately prior to the election of the nominees for director at the [YEAR] annual meeting of shareholders of the Company, or if earlier, on September 30, [YEAR], provided that the Participant is providing services to the Company or a Subsidiary as of such time.

Notwithstanding the foregoing, upon the occurrence of a Change in Control, all Unvested RSUs shall immediately vest and become Vested RSUs.

b.    Subject to the provisions of the Plan and this Agreement and provided that the Awarded Units have not been forfeited pursuant to Section 4 below, Vested RSUs shall be delivered within thirty (30) days of the applicable vesting dates of the Awarded Units in accordance with Section 3.a. above. The Company shall convert such Awarded Units (to the extent such Awarded Units are Vested RSUs) into the number of whole shares of Common Stock equal to the number of

- 1 -

Awarded Units converted and shall deliver to the Participant or the Participant’s personal representative such shares of Common Stock.

4.Forfeiture of Awarded Units. The Participant shall be deemed to have forfeited all of the Participant’s Unvested RSUs upon the Participant’s Total and Permanent Disability, death or upon the Participant’s Termination of Service forany reason.

Upon forfeiture, all of the Participant’s rights with respect to the forfeited Unvested RSUs shall cease and terminate, without any further obligations on the part of the Company.

5.Who May Receive Converted Awarded Units. During the lifetime of the Participant, the Common Stock received upon conversion of Awarded Units may only be received by the Participant or his or her legal representative. If the Participant dies after the time that his or her Awarded Units become vested but prior to the time his or her Awarded Units are converted into shares of Common Stock, the Common Stock relating to such converted Awarded Units may be received by any individual who is entitled to receive the property of the Participant pursuant to the applicable laws of descent and distribution.

6.No Fractional Shares. Awarded Units may be converted only with respect to full shares, and no fractional share of Common Stock shall be issued.

7.Nonassignability. The Awarded Units are not assignable or transferable by the Participant except by will or by the laws of descent and distribution.

8.Rights as Shareholder. The Participant will have no rights as a shareholder with respect to any shares covered by this Agreement until the issuance of a certificate or certificates to the Participant or the registration of such shares in the Participant’s name for the shares of Common Stock. The Awarded Units shall be subject to the terms and conditions of this Agreement. Except as otherwise provided in Section 9 hereof, no adjustment shall be made for dividends or other rights for which the record date is prior to the issuance of such shares of Common Stock. The Participant, by his or her execution of this Agreement, agrees to execute any documents requested by the Company in connection with the issuance of such shares of Common Stock.

9.Adjustment of Number of Awarded Units and Related Matters. The number of shares of Common Stock covered by the Awarded Units shall be subject to adjustment in accordance with Articles 11-13 of the Plan.

10.Specific Performance. The parties acknowledge that remedies at law will be inadequate remedies for breach of this Agreement and consequently agree that this Agreement shall be enforceable by specific performance. The remedy of specific performance shall be cumulative of all of the rights and remedies at law or in equity of the parties under this Agreement.

11.Participant’s Representations. Notwithstanding any of the provisions hereof, the Participant hereby agrees that the Company will not be obligated to issue any shares of Common Stock to the Participant hereunder, if the issuance of such shares shall constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority. Any determination in this connection by the Company shall be final, binding, and conclusive. The obligations of the Company and the rights of the Participant are subject to all applicable laws, rules, and regulations.

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12.Investment Representation. Unless the shares of Common Stock are issued to the Participant in a transaction registered under applicable federal and state securities laws, by his or her execution hereof, the Participant represents and warrants to the Company that all Common Stock which may be acquired hereunder will be acquired by the Participant for investment purposes for his or her own account and not with any intent for resale or distribution in violation of federal or state securities laws. Unless the Common Stock is issued to the Participant in a transaction registered under the applicable federal and state securities laws, all certificates issued with respect to the Common Stock shall bear an appropriate restrictive investment legend and shall be held indefinitely, unless they are subsequently registered under the applicable federal and state securities laws or the Participant obtains an opinion of counsel, in form and substance satisfactory to the Company and its counsel, that such registration is not required.

13.Participant’s Acknowledgments. The Participant acknowledges that a copy of the Plan has been made available for his or her review by the Company, and represents that he or she is familiar with the terms and provisions thereof, and hereby accepts this Award subject to all the terms and provisions thereof. The Participant hereby agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee or the Board, as appropriate, upon any questions arising under the Plan or this Agreement.

14.Law Governing. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas (excluding any conflict of laws rule or principle of Texas law that might refer the governance, construction, or interpretation of this Agreement to the laws of another state).

15.No Right to Continue Service. Nothing herein shall be construed to confer upon the Participant the right to continue to provide services to the Company or any Subsidiary, or interfere with or restrict in any way the right of the Company or any Subsidiary to discharge the Participant at any time.

16.Legal Construction. In the event that any one or more of the terms, provisions, or agreements that are contained in this Agreement shall be held by a court of competent jurisdiction to be invalid, illegal, or unenforceable in any respect for any reason, the invalid, illegal, or unenforceable term, provision, or agreement shall not affect any other term, provision, or agreement that is contained in this Agreement and this Agreement shall be construed in all respects as if the invalid, illegal, or unenforceable term, provision, or agreement had never been contained herein.

17.Covenants and Agreements as Independent Agreements. Each of the covenants and agreements that is set forth in this Agreement shall be construed as a covenant and agreement independent of any other provision of this Agreement. The existence of any claim or cause of action of the Participant against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants and agreements that are set forth in this Agreement.

18.Entire Agreement. This Agreement together with the Plan (as each may be amended from time to time) supersede any and all other prior understandings and agreements, either oral or in writing, between the parties with respect to the subject matter hereof and constitute the sole and only agreements between the parties with respect to the said subject matter. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Plan. Each party to this Agreement acknowledges that no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement or the Plan and that any agreement, statement or promise that is not contained in this Agreement or the Plan shall not be valid or binding or of any force or effect.

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19.Parties Bound. The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein.

20.Modification. No change or modification of this Agreement shall be valid or binding upon the parties unless the change or modification is in writing and signed by the parties; provided, however, that the Company may change or modify this Agreement without the Participant’s consent or signature if the Company determines, in its sole discretion, that such change or modification is necessary for purposes of compliance with or exemption from the requirements of Code Section 409A or any regulations or other guidance issued thereunder. To the extent that any provision hereof is modified in order to comply with Code Section 409A, such modification shall be made in good faith and shall, to the maximum extent reasonably possible, maintain the original intent and economic benefit to the Participant and the Company of the applicable provision without violating the provisions of Code Section 409A, and in no event may any such amendment modify the time or form of payment of any amount payable pursuant to this Agreement if such modification would be in violation of Code Section 409A. Notwithstanding the provisions of this Section 20, the Company may amend the Plan to the extent permitted by the Plan.

21.Headings. The headings that are used in this Agreement are used for reference and convenience purposes only and do not constitute substantive matters to be considered in construing the terms and provisions of this Agreement.

22.Gender and Number. Words of any gender used in this Agreement shall be held and construed to include any other gender, and words in the singular number shall be held to include the plural, and vice versa, unless the context requires otherwise.

23.Notice. Any notice required or permitted to be delivered hereunder shall be deemed to be delivered only when actually received by the Company or by the Participant, as the case may be, at the addresses set forth below, or at such other addresses as they have theretofore specified by written notice delivered in accordance herewith:

a.    Notice to the Company shall be addressed and delivered as follows:

Matador Resources Company

5400 LBJ Fwy, Suite 1500

Dallas, TX 75240

Attn: General Counsel

Facsimile: (972) 371-5201

b.    Notice to the Participant shall be addressed and delivered as set forth on the signature page.

24.Tax Requirements. The Participant is hereby advised to consult immediately with his or her own tax advisor regarding the tax consequences of this Agreement. The Participant, as an Outside Director, shall be solely responsible for withholding taxes or any necessary payments to any taxing authority in connection with the conversion of the Awarded Units.

25.Code Section 409A. This Agreement is intended to be interpreted and applied so that the payments and benefits set forth herein shall comply with or be exempt from the requirements of Code Section

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409A, and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to the fullest extent possible to reflect and implement such intent. Notwithstanding anything in this Agreement and in the event the payments and benefits set forth herein are subject to Code Section 409A, (i) a Termination of Service shall not be deemed to have occurred for purposes of any provision of this Agreement unless such termination is also a “separation from service” within the meaning of Code Section 409A; and (ii) a Total and Permanent Disability shall not be deemed to have occurred for purposes of any provision of this Agreement unless such disability is also a “disability” within the meaning of Code Section 409A. Notwithstanding any provision in this Agreement to the contrary, if on his or her Termination of Service, the Participant is deemed to be a “specified employee” within the meaning of Code Section 409A, any payments or benefits due upon such Termination of Service that constitutes a “deferral of compensation” within the meaning of Code Section 409A and which do not otherwise qualify under the exemptions under Treas. Reg. § 1.409A-1 (including without limitation, the short-term deferral exemption and the permitted payments under Treas. Reg. § 1.409A-1(b)(9)(iii)(A)), shall be delayed and paid or provided to the Participant on the earlier of the date which immediately follows six (6) months after the Participant’s separation from service or, if earlier, the date of the Participant’s death.

* * * * * * * *

[Remainder of Page Intentionally Left Blank

Signature Page Follows.]

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant, to evidence his or her consent and approval of all the terms hereof, has duly executed this Agreement, as of the date specified in Section 1 hereof.

COMPANY:

MATADOR RESOURCES COMPANY

By:    _______________________________________

Name:    

Title:    

PARTICIPANT:

_____________________________________________

Signature

Name:    ______________________________________

Address: _____________________________________

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EX-10.4

Exhibit 10.4

RESTRICTED STOCK UNIT AWARD AGREEMENT

MATADOR RESOURCES COMPANY AMENDED AND RESTATED

2012 LONG-TERM INCENTIVE PLAN

1.Award of Restricted Stock Units. Pursuant to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “Plan”) for Employees, Contractors, and Outside Directors of Matador Resources Company, a Texas corporation (the “Company”), the Company grants to

[NAME]

(the “Participant”),

an Outside Director of the Company, an Award under the Plan for [NUMBER]Restricted Stock Units (the “Awarded Units”) which may be converted into the number of shares of Common Stock of the Company equal to the number of Restricted Stock Units, subject to (i) the terms and conditions of the Plan and this Restricted Stock Unit Award Agreement (this “Agreement”) and, to the extent applicable, (ii) any deferral election validly made with respect to the Awarded Units (the “Election”) pursuant to the Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (the “Deferral Plan”). The “Date of Grant” of this Restricted Stock Unit Award is [DATE]. Each Awarded Unit shall be a notional share of Common Stock, with the value of each Awarded Unit being equal to the Fair Market Value of a share of Common Stock at any time. Capitalized terms used in this Agreement that are defined in the Plan shall have the same meanings assigned to them in the Plan.

2.Subject to Plan and Election. This Agreement is subject to the terms and conditions of the Plan and the Election. With respect to the Plan, (i) the terms of the Plan shall control to the extent such terms are not otherwise inconsistent with the provisions of this Agreement, and (ii) the terms of the Agreement shall control to the extent such terms are inconsistent with the provisions of the Plan. With respect to the Election, (x) the terms of this Agreement shall control to the extent such terms are not otherwise inconsistent with the provisions of the Election, and (y) the terms of the Election shall control to the extent such terms are inconsistent with the provisions of the Agreement. Except as otherwise provided herein, the Election shall be deemed to be part of this Agreement and references herein to this Agreement shall, when applicable, be deemed to include references to the Election. The Election shall be attached as an exhibit to this Agreement, provided that, failure to attach the Election to this Agreement shall in no way affect the validity and effect of the Election. This Agreement and the Election are subject to any rules promulgated pursuant to the Plan and the Deferral Plan, respectively, by the Board or the Committee and communicated to the Participant in writing.

3.Vesting; Time of Delivery of Shares. Awarded Units which have become vested pursuant to the terms of this Section 3 are collectively referred to herein as “Vested RSUs.” All other Awarded Units are collectively referred to herein as “Unvested RSUs.”

a.    Except as specifically provided in this Agreement and subject to certain restrictions and conditions set forth in the Plan, the Awarded Units shall be vested as follows:

One hundred percent (100%) of the total Awarded Units shall vest and become Vested RSUs immediately prior to the election of the nominees for director at the [YEAR] annual meeting of shareholders of the Company, or if earlier, on September 30, [YEAR], provided that the Participant is providing services to the Company or a Subsidiary as of such time.

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Notwithstanding the foregoing, upon the occurrence of a Change in Control, all Unvested RSUs shall immediately vest and become Vested RSUs.

b.    Subject to the provisions of the Plan, the Election and this Agreement and provided that the Awarded Units have not been forfeited pursuant to Section 4 below, Vested RSUs shall be delivered as follows:

i.With respect to any Awarded Units that are not subject to the Election, within thirty (30) days of the applicable vesting dates of such Awarded Units in accordance with Section 3.a. above, the Company shall convert such Awarded Units (to the extent such Awarded Units are Vested RSUs) into the number of whole shares of Common Stock equal to the number of Awarded Units converted and shall deliver to the Participant or the Participant’s personal representative such shares of Common Stock.

ii.With respect to any Awarded Units that are subject to the Election, within thirty (30) days of the applicable payment date or other payment event set forth in the Election, the Company shall convert such Awarded Units (to the extent such Awarded Units are Vested RSUs) into the number of whole shares of Common Stock equal to the number of Awarded Units converted and shall deliver to the Participant or the Participant’s personal representative such shares of Common Stock.

4.Forfeiture of Awarded Units. The Participant shall be deemed to have forfeited all of the Participant’s Unvested RSUs upon the Participant’s Total and Permanent Disability, death or upon the Participant’s Termination of Service for any reason.

Upon forfeiture, all of the Participant’s rights with respect to the forfeited Unvested RSUs shall cease and terminate, without any further obligations on the part of the Company.

5.Who May Receive Converted Awarded Units. During the lifetime of the Participant, the Common Stock received upon conversion of Awarded Units may only be received by the Participant or his or her legal representative. If the Participant dies after the time that his or her Awarded Units become vested but prior to the time his or her Awarded Units are converted into shares of Common Stock, the Common Stock relating to such converted Awarded Units may be received by any individual who is entitled to receive the property of the Participant pursuant to the applicable laws of descent and distribution.

6.No Fractional Shares. Awarded Units may be converted only with respect to full shares, and no fractional share of Common Stock shall be issued.

7.Nonassignability. The Awarded Units are not assignable or transferable by the Participant except by will or by the laws of descent and distribution.

8.Rights as Shareholder. The Participant will have no rights as a shareholder with respect to any shares covered by this Agreement until the issuance of a certificate or certificates to the Participant or the registration of such shares in the Participant’s name for the shares of Common Stock. The Awarded Units shall be subject to the terms and conditions of this Agreement. Except as otherwise provided in Section 9 hereof, no adjustment shall be made for dividends or other rights for which the record date is prior to the issuance of such shares of Common Stock. The Participant, by his or her execution of this Agreement, agrees to execute any documents requested by the Company in connection with the issuance of such shares of Common Stock.

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9.Adjustment of Number of Awarded Units and Related Matters. The number of shares of Common Stock covered by the Awarded Units shall be subject to adjustment in accordance with Articles 11-13 of the Plan.

10.Specific Performance. The parties acknowledge that remedies at law will be inadequate remedies for breach of this Agreement and consequently agree that this Agreement shall be enforceable by specific performance. The remedy of specific performance shall be cumulative of all of the rights and remedies at law or in equity of the parties under this Agreement.

11.Participant’s Representations. Notwithstanding any of the provisions hereof, the Participant hereby agrees that the Company will not be obligated to issue any shares of Common Stock to the Participant hereunder, if the issuance of such shares shall constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority. Any determination in this connection by the Company shall be final, binding, and conclusive. The obligations of the Company and the rights of the Participant are subject to all applicable laws, rules, and regulations.

12.Investment Representation. Unless the shares of Common Stock are issued to the Participant in a transaction registered under applicable federal and state securities laws, by his or her execution hereof, the Participant represents and warrants to the Company that all Common Stock which may be acquired hereunder will be acquired by the Participant for investment purposes for his or her own account and not with any intent for resale or distribution in violation of federal or state securities laws. Unless the Common Stock is issued to the Participant in a transaction registered under the applicable federal and state securities laws, all certificates issued with respect to the Common Stock shall bear an appropriate restrictive investment legend and shall be held indefinitely, unless they are subsequently registered under the applicable federal and state securities laws or the Participant obtains an opinion of counsel, in form and substance satisfactory to the Company and its counsel, that such registration is not required.

13.Participant’s Acknowledgments. The Participant acknowledges that copies of the Plan and Deferral Plan have been made available for his or her review by the Company, and represents that he or she is familiar with the terms and provisions thereof, and hereby accepts this Award subject to all the terms and provisions thereof. The Participant hereby agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee or the Board, as appropriate, upon any questions arising under the Plan or this Agreement.

14.Law Governing. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas (excluding any conflict of laws rule or principle of Texas law that might refer the governance, construction, or interpretation of this Agreement to the laws of another state).

15.No Right to Continue Service. Nothing herein shall be construed to confer upon the Participant the right to continue to provide services to the Company or any Subsidiary, or interfere with or restrict in any way the right of the Company or any Subsidiary to discharge the Participant at any time.

16.Legal Construction. In the event that any one or more of the terms, provisions, or agreements that are contained in this Agreement shall be held by a court of competent jurisdiction to be invalid, illegal, or unenforceable in any respect for any reason, the invalid, illegal, or unenforceable term, provision, or agreement shall not affect any other term, provision, or agreement that is contained in this Agreement and this Agreement shall be construed in all respects as if the invalid, illegal, or unenforceable term, provision, or agreement had never been contained herein.

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17.Covenants and Agreements as Independent Agreements. Each of the covenants and agreements that is set forth in this Agreement shall be construed as a covenant and agreement independent of any other provision of this Agreement. The existence of any claim or cause of action of the Participant against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants and agreements that are set forth in this Agreement.

18.Entire Agreement. This Agreement together with the Plan (as each may be amended from time to time) supersede any and all other prior understandings and agreements, either oral or in writing, between the parties with respect to the subject matter hereof and constitute the sole and only agreements between the parties with respect to the said subject matter. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Plan. Each party to this Agreement acknowledges that no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement or the Plan and that any agreement, statement or promise that is not contained in this Agreement or the Plan shall not be valid or binding or of any force or effect.

19.Parties Bound. The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein.

20.Modification. No change or modification of this Agreement shall be valid or binding upon the parties unless the change or modification is in writing and signed by the parties; provided, however, that the Company may change or modify this Agreement without the Participant’s consent or signature if the Company determines, in its sole discretion, that such change or modification is necessary for purposes of compliance with or exemption from the requirements of Code Section 409A or any regulations or other guidance issued thereunder. To the extent that any provision hereof is modified in order to comply with Code Section 409A, such modification shall be made in good faith and shall, to the maximum extent reasonably possible, maintain the original intent and economic benefit to the Participant and the Company of the applicable provision without violating the provisions of Code Section 409A, and in no event may any such amendment modify the time or form of payment of any amount payable pursuant to this Agreement if such modification would be in violation of Code Section 409A. Notwithstanding the provisions of this Section 20, the Company may amend the Plan to the extent permitted by the Plan.

21.Headings. The headings that are used in this Agreement are used for reference and convenience purposes only and do not constitute substantive matters to be considered in construing the terms and provisions of this Agreement.

22.Gender and Number. Words of any gender used in this Agreement shall be held and construed to include any other gender, and words in the singular number shall be held to include the plural, and vice versa, unless the context requires otherwise.

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23.Notice. Any notice required or permitted to be delivered hereunder shall be deemed to be delivered only when actually received by the Company or by the Participant, as the case may be, at the addresses set forth below, or at such other addresses as they have theretofore specified by written notice delivered in accordance herewith:

a.    Notice to the Company shall be addressed and delivered as follows:

Matador Resources Company

5400 LBJ Fwy, Suite 1500

Dallas, TX 75240

Attn: General Counsel

Facsimile: (972) 371-5201

b.    Notice to the Participant shall be addressed and delivered as set forth on the signature page.

24.Tax Requirements. The Participant is hereby advised to consult immediately with his or her own tax advisor regarding the tax consequences of this Agreement. The Participant, as an Outside Director, shall be solely responsible for withholding taxes or any necessary payments to any taxing authority in connection with the conversion of the Awarded Units.

25.Code Section 409A. This Agreement is intended to be interpreted and applied so that the payments and benefits set forth herein shall, as applicable, comply with or be exempt from the requirements of Code Section 409A, and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to the fullest extent possible to reflect and implement such intent. Notwithstanding anything in this Agreement and to the extent the payments and benefits set forth herein are subject to Code Section 409A, (i) a Termination of Service shall not be deemed to have occurred for purposes of any provision of this Agreement unless such termination is also a “separation from service” within the meaning of Code Section 409A; and (ii) a Total and Permanent Disability shall not be deemed to have occurred for purposes of any provision of this Agreement unless such disability is also a “disability” within the meaning of Code Section 409A. Notwithstanding any provision in this Agreement to the contrary, if on his or her Termination of Service, the Participant is deemed to be a “specified employee” within the meaning of Code Section 409A, any payments or benefits due upon such Termination of Service that constitutes a “deferral of compensation” within the meaning of Code Section 409A and which do not otherwise qualify under the exemptions under Treas. Reg. § 1.409A-1 (including without limitation, the short-term deferral exemption and the permitted payments under Treas. Reg. § 1.409A-1(b)(9)(iii)(A)), shall be delayed and paid or provided to the Participant on the earlier of the date which immediately follows six (6) months after the Participant’s separation from service or, if earlier, the date of the Participant’s death.

* * * * * * * *

[Remainder of Page Intentionally Left Blank

Signature Page Follows.]

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant, to evidence his or her consent and approval of all the terms hereof, has duly executed this Agreement, as of the date specified in Section 1 hereof.

COMPANY:

MATADOR RESOURCES COMPANY

By:    _______________________________________

Name:    

Title:    

PARTICIPANT:

_____________________________________________

Signature

Name:    ______________________________________

Address: _____________________________________

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EXHIBIT

- 7 -

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use of the name Netherland, Sewell & Associates, Inc.; the references to our audit of Matador Resources Company’s proved oil and natural gas reserves estimates and future net revenue at June 30, 2017; and the inclusion of our corresponding audit letter, dated July 31, 2017, in this Quarterly Report on Form 10-Q of Matador Resources Company for the fiscal quarter ended June 30, 2017, as well as in the notes to the financial statements included therein. In addition, we hereby consent to the incorporation by reference of our audit letter, dated July 31, 2017, in Matador Resources Company’s Forms S-8 (File No. 333-180641 and File No. 333-204868).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ G. Lance Binder, P.E.
	G. Lance Binder, P.E.
	Executive Vice President

Dallas, Texas

August 4, 2017

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Joseph Wm. Foran, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 7, 2017	/s/ Joseph Wm. Foran
	Joseph Wm. Foran
	Chairman and Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, David E. Lancaster, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 7, 2017	/s/ David E. Lancaster
	David E. Lancaster Executive Vice President and Chief Financial Officer (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Matador Resources Company (the “Company”) on Form 10-Q for the period ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Joseph Wm. Foran, hereby certify in my capacity as Chairman and Chief Executive Officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 7, 2017	/s/ Joseph Wm. Foran
	Joseph Wm. Foran
	Chairman and Chief Executive Officer (Principal Executive Officer)

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Matador Resources Company (the “Company”) on Form 10-Q for the period ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, David E. Lancaster, hereby certify in my capacity as Executive Vice President and Chief Financial Officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 7, 2017	/s/ David E. Lancaster
	David E. Lancaster
	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

EX-99.1

Exhibit 99.1

[Netherland, Sewell & Associates, Inc. Letterhead]

July 31, 2017

Mr. Brad Robinson

MRC Energy Company

One Lincoln Centre

5400 LBJ Freeway, Suite 1500

Dallas, Texas 75240

Dear Mr. Robinson:

In accordance with your request, we have audited the estimates prepared by MRC Energy Company (MRC), as of June 30, 2017, of the proved reserves and future revenue to the MRC interest in certain oil and gas properties located in Louisiana, New Mexico, and Texas. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by MRC. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, except that per-well overhead expenses are excluded for the operated properties and future income taxes are excluded for all properties. We completed our audit on or about the date of this letter. This report has been prepared for MRC's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth MRC's estimates of the net reserves and future net revenue, as of June 30, 2017, for the audited properties:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	27,780	158,498	961,581	660,489
Proved Developed Non-Producing	675	1,232	22,976	18,340
Proved Undeveloped	46,500	196,787	922,199	408,060
Total Proved	74,954	356,517	1,906,756	1,086,889

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a well-by-well basis, some of the estimates of MRC are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of MRC's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by MRC in preparing the June 30, 2017, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by MRC.

The estimates shown herein are for proved reserves. MRC's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. MRC has included estimates of proved undeveloped reserves for certain MRC-operated locations that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These MRC-operated locations have been included based on MRC's declared intent to drill these wells, as evidenced by MRC's internal budget, reserves estimates, and price forecast. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by MRC are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2016 through June 2017. For oil volumes, the average West Texas Intermediate posted price of $45.42 per barrel is adjusted by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.01 per MMBTU is adjusted by lease for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $45.77 per barrel of oil and $2.39 per MCF of gas.

Operating costs used by MRC are based on historical operating expense records. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs. For all properties, headquarters general and administrative overhead expenses of MRC are not included. Capital costs used by MRC are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Operating costs and capital costs are not escalated for inflation. Estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of MRC and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by MRC, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by MRC with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of MRC's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by MRC, are on file in our office. The technical person primarily responsible for conducting this audit meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. G. Lance Binder, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1983 and has over 5 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:        

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ G. Lance Binder

By:        

G. Lance Binder, P.E. 61794

Executive Vice President

Date Signed: July 31, 2017

GLB:SDB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

CERTIFICATION OF QUALIFICATION

I, G. Lance Binder, Licensed Professional Engineer, 2100 Ross Avenue, Suite 2200, Dallas, Texas, hereby certify:

That I am an employee of Netherland, Sewell & Associates, Inc. in the position of Executive Vice President.

That I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Matador Resources Company or its subsidiaries.

That I attended Purdue University and graduated in 1978 with a Bachelor of Science Degree in Chemical Engineering; that I am a Licensed Professional Engineer in the State of Texas, United States of America; and that I have in excess of 35 years of experience in petroleum engineering studies and evaluations.

By: /s/ G. Lance Binder

G. Lance Binder, P.E.

Texas Registration No. 61794

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 02, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	Matador Resources Co
Entity Central Index Key	0001520006
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		100,437,295

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Condensed Consolidated Balance Sheets - Unaudited - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets
Cash	$ 131,466	$ 212,884
Restricted cash	15,040	1,258
Accounts receivable
Oil and natural gas revenues	39,621	34,154
Joint interest billings	37,387	19,347
Other	7,303	5,167
Derivative instruments	7,067	0
Lease and well equipment inventory	2,957	3,045
Prepaid expenses and other assets	5,946	3,327
Total current assets	246,787	279,182
Oil and natural gas properties, full-cost method
Evaluated	2,694,766	2,408,305
Unproved and unevaluated	567,009	479,736
Other property and equipment	204,299	160,795
Less accumulated depletion, depreciation and amortization	(1,939,570)	(1,864,311)
Net property and equipment	1,526,504	1,184,525
Derivative instruments	2,992	0
Other assets	793	958
Total other assets	3,785	958
Total assets	1,777,076	1,464,665
Current liabilities
Accounts payable	7,371	4,674
Accrued liabilities	151,336	101,460
Royalties payable	35,423	23,988
Amounts due to affiliates	5,865	8,651
Derivative instruments	1,192	24,203
Advances from joint interest owners	5,468	1,700
Amounts due to joint ventures	4,873	4,251
Other current liabilities	656	578
Total current liabilities	212,184	169,505
Long-term liabilities
Senior unsecured notes payable	573,988	573,924
Asset retirement obligations	22,391	19,725
Amounts due to joint ventures	0	751
Derivative instruments	0	1,771
Other long-term liabilities	6,142	7,544
Total long-term liabilities	602,521	603,715
Commitments and contingencies
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 100,399,756 and 99,518,764 shares issued; and 100,324,852 and 99,511,931 shares outstanding, respectively	1,004	995
Additional paid-in capital	1,453,341	1,325,481
Accumulated deficit	(563,858)	(636,351)
Treasury stock, at cost, 74,904 and 6,833 shares, respectively	(745)	0
Total Matador Resources Company shareholders’ equity	889,742	690,125
Non-controlling interest in subsidiaries	72,629	1,320
Total shareholders’ equity	962,371	691,445
Total liabilities and shareholders’ equity	$ 1,777,076	$ 1,464,665

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Condensed Consolidated Balance Sheets (Parenthetical) - Unaudited - $ / shares	Jun. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	100,399,756	99,518,764
Common stock, shares outstanding	100,324,852	99,511,931
Treasury stock, shares	74,904	6,833

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Condensed Consolidated Statements of Operations - Unaudited - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues
Oil and natural gas revenues	$ 113,764	$ 69,336	$ 228,611	$ 113,262
Third-party midstream services revenues	2,099	918	3,654	1,391
Realized gain (loss) on derivatives	558	2,465	(1,661)	9,528
Unrealized gain (loss) on derivatives	13,190	(26,625)	33,821	(33,464)
Total revenues	129,611	46,094	264,425	90,717
Expenses
Production taxes, transportation and processing	12,875	10,556	24,682	18,459
Lease operating	16,040	12,183	31,797	26,695
Plant and other midstream services operating	2,942	1,061	5,283	2,088
Depletion, depreciation and amortization	41,274	31,248	75,266	60,170
Accretion of asset retirement obligations	314	289	614	552
Full-cost ceiling impairment	0	78,171	0	158,633
General and administrative	17,177	13,197	33,515	26,360
Total expenses	90,622	146,705	171,157	292,957
Operating income (loss)	38,989	(100,611)	93,268	(202,240)
Other income (expense)
Net gain on asset sales and inventory impairment	0	1,002	7	2,067
Interest expense	(9,224)	(6,167)	(17,679)	(13,365)
Other income	1,922	29	1,991	124
Total other expense	(7,302)	(5,136)	(15,681)	(11,174)
Net income (loss)	31,687	(105,747)	77,587	(213,414)
Net income attributable to non-controlling interest in subsidiaries	(3,178)	(106)	(5,094)	(93)
Net income (loss) attributable to Matador Resources Company shareholders	$ 28,509	$ (105,853)	$ 72,493	$ (213,507)
Earnings (loss) per common share
Basic (in dollars per share)	$ 0.28	$ (1.15)	$ 0.72	$ (2.40)
Diluted (in dollars per share)	$ 0.28	$ (1.15)	$ 0.72	$ (2.40)
Weighted average common shares outstanding
Basic (shares)	100,211	92,346	100,005	88,826
Diluted (shares)	100,227	92,346	100,455	88,826

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Condensed Consolidated Statement of Changes in Shareholders' Equity - Unaudited - 6 months ended Jun. 30, 2017 - USD ($) $ in Thousands	Total	Common Stock	Additional paid-in capital	Accumulated deficit	Treasury Stock	Total shareholders’ equity attributable to Matador Resources Company	Non-controlling interest in subsidiaries
Beginning Balance, shares at Dec. 31, 2016	99,511,931	99,519,000			6,000
Balance at January 1, 2017 at Dec. 31, 2016	$ 691,445	$ 995	$ 1,325,481	$ (636,351)	$ 0	$ 690,125	$ 1,320
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock pursuant to employee stock compensation plan, shares		499,000
Issuance of common stock pursuant to employee stock compensation plan	0	$ 5	(5)			0
Common stock issued to Board members and advisors, shares		55,000
Common stock issued to Board members and advisors	0	$ 1	(1)			0
Stock-based compensation expense related to equity-based awards including amounts capitalized	12,521		12,521			12,521
Stock options exercised, shares		327,000
Stock options exercised, net of options forfeited in net share settlements	(24)	$ 3	(27)			(24)
Restricted stock forfeited, shares					69,000
Restricted stock forfeited	(745)				$ (745)	(745)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653)		(1,250)			(1,250)	(1,403)
Contributions related to formation of Joint Venture (see Note 3)	171,500		116,622			116,622	54,878
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	14,700						14,700
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(1,960)						(1,960)
Current period net income	$ 77,587			72,493		72,493	5,094
Ending Balance, shares at Jun. 30, 2017	100,324,852	100,400,000			75,000
Balance at March 31, 2017 at Jun. 30, 2017	$ 962,371	$ 1,004	$ 1,453,341	$ (563,858)	$ (745)	$ 889,742	$ 72,629

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Condensed Consolidated Statements of Cash Flows - Unaudited - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating activities
Net income (loss)	$ 77,587	$ (213,414)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(33,821)	33,464
Depletion, depreciation and amortization	75,266	60,170
Accretion of asset retirement obligations	614	552
Full-cost ceiling impairment	0	158,633
Stock-based compensation expense	11,192	5,553
Amortization of debt issuance cost	64	592
Net gain on asset sales and inventory impairment	(7)	(2,067)
Changes in operating assets and liabilities
Accounts receivable	(25,642)	(2,751)
Lease and well equipment inventory	(140)	(514)
Prepaid expenses	(2,619)	186
Other assets	165	520
Accounts payable, accrued liabilities and other current liabilities	4,442	2,451
Royalties payable	11,435	153
Advances from joint interest owners	3,768	5,083
Income taxes payable	0	(2,848)
Other long-term liabilities	(1,062)	3,837
Net cash provided by operating activities	121,242	49,600
Investing activities
Oil and natural gas properties capital expenditures	(328,929)	(162,381)
Expenditures for other property and equipment	(41,743)	(47,548)
Proceeds from sale of assets	977	0
Restricted cash	0	43,437
Restricted cash in less-than-wholly-owned subsidiaries	(13,783)	460
Net cash used in investing activities	(383,478)	(166,032)
Financing activities
Proceeds from issuance of common stock	0	142,350
Cost to issue equity	0	(768)
Proceeds from stock options exercised	2,201	0
Contributions related to formation of Joint Venture	171,500	0
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	14,700	0
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(1,960)	0
Taxes paid related to net share settlement of stock-based compensation	(2,970)	(1,009)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653)	0
Net cash provided by financing activities	180,818	140,573
(Decrease) increase in cash	(81,418)	24,141
Cash at beginning of period	212,884	16,732
Cash at end of period	$ 131,466	$ 40,873

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Nature of Operations

6 Months Ended

Jun. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF OPERATIONS

NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is 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. The Company’s 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

The interim unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Annual Report”) filed with the SEC. The Company consolidates certain subsidiaries and joint ventures that are less than wholly owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less than wholly owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments, consisting only of normal, recurring adjustments, which are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of June 30, 2017. Amounts as of December 31, 2016 are derived from the Company’s audited consolidated financial statements in the Annual Report.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the prior periods’ financial statements to conform to the current period presentation. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting. As a result, $0.9 million for the three months ended June 30, 2016 and $1.4 million for the six months ended June 30, 2016 were reclassified from other income to third-party midstream services revenues. In addition, $1.1 million related to midstream operating costs for the three months ended June 30, 2016 and $2.1 million for the six months ended June 30, 2016 were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For the three and six months ended June 30, 2017, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties; no impairment charge was necessary. However, due primarily to declines in oil and natural gas prices in early 2016, the capitalized costs of oil and natural gas properties exceeded the cost center ceiling for the three and six months ended June 30, 2016, and as a result, the Company recorded impairment charges to its net capitalized costs of $78.2 million and $158.6 million, respectively, in its interim unaudited condensed consolidated statements of operations.

The Company capitalized approximately $5.2 million and $4.0 million of its general and administrative costs for the three months ended June 30, 2017 and 2016, respectively, and approximately $1.9 million and $1.7 million of its interest expense for the three months ended June 30, 2017 and 2016, respectively. The Company capitalized approximately $10.8 million and $6.0 million of its general and administrative costs for the six months ended June 30, 2017 and 2016, respectively, and approximately $3.2 million and $2.2 million of its interest expense for the six months ended June 30, 2017 and 2016, respectively.

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive.

The following table sets forth the computation of diluted weighted average common shares outstanding for the three and six months ended June 30, 2017 and 2016 (in thousands).

	Three Months Ended   June 30,		Six Months Ended   June 30,
	2017	2016	2017	2016
Weighted average common shares outstanding
Basic	100,211	92,346	100,005	88,826
Dilutive effect of options and restricted stock units	16	—	450	—
Diluted weighted average common shares outstanding	100,227	92,346	100,455	88,826

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the diluted weighted average common shares outstanding for both the three and six months ended June 30, 2016, respectively, because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for both the three and six months ended June 30, 2016, respectively, as the security holders do not have the obligation to share in the losses of the Company.

Recent Accounting Pronouncements

Revenue from Contracts with Customers.In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company expects to adopt the new guidance effective January 1, 2018 using the modified approach. The Company is evaluating the new guidance, including (i) identification of revenue streams and (ii) review of contracts and procedures currently in place.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842),which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The update should be applied using a retrospective transition method to each period presented. The Company believes that the impact of the adoption of this ASU will change the presentation of its beginning and ending cash balances on its Consolidated Statements of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing activities on its Consolidated Statements of Cash Flows.

Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted. Entities are required to apply guidance prospectively upon adoption. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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Business Combination

6 Months Ended

Jun. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Business Combination

BUSINESS COMBINATION

Joint Venture

On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets. The Company retained its ownership in certain midstream assets in South Texas and Northwest Louisiana, which are not part of the Joint Venture.

The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution. The Company may earn an additional $73.5 million in performance incentives over the next five years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140.0 million in the aggregate to expand the Joint Venture’s midstream operations and asset base. The Joint Venture is consolidated in the Company’s interim unaudited condensed consolidated financial statements with Five Point’s interest in the Joint Venture being accounted for as a non-controlling interest.

In connection with the Joint Venture, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed fee natural gas processing agreement (see Note 10).

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2017 (in thousands).

Beginning asset retirement obligations	$	20,640
Liabilities incurred during period	1,222
Liabilities settled during period	(176		)
Revisions in estimated cash flows	794
Accretion expense	614
Ending asset retirement obligations	23,094
Less: current asset retirement obligations(1)	(703		)
Long-term asset retirement obligations	$	22,391

 _______________

(1) Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2017.

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Debt

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

DEBT

DEBT

At June 30, 2017 and August 2, 2017, the Company had $575.0 million of outstanding 6.875% senior notes due 2023, no borrowings outstanding under the Company’s revolving credit agreement (the “Credit Agreement”) and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

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 the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2016, and on April 28, 2017, the borrowing base was increased to $450.0 million and the maximum facility amount remained at $500.0 million. The Company elected to keep the borrowing commitment at $400.0 million. Borrowings under the Credit Agreement are limited to the least of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020.

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $1.1 million at June 30, 2017, and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company 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 to repay the deficit in equal installments over a period of six months.

The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2017.

Senior Unsecured Notes

On April 14, 2015 and December 9, 2016, the Company issued$400.0 million and $175.0 million, respectively, of 6.875% senior notes due 2023 (collectively, the “Notes”). The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April and October 15 of each year.

On May 24, 2017, and pursuant to a registered exchange offer, the Company exchanged all of the $175.0 million of Notes issued on December 9, 2016, which were privately placed, for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act of 1933, as amended. The terms of such registered Notes are substantially the same as the terms of the original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the original Notes do not apply to the registered Notes.

On February 17, 2017, in connection with the formation of San Mateo (see Note 3), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted subsidiaries under the indenture governing the Notes.

The following presents condensed consolidating financial information on an issuer (Matador), Non-Guarantor Subsidiaries, Guarantor Subsidiaries and consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheet June 30, 2017
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	385,885	$	—	$	1,679	$	(387,564	)	$	—
Third-party current assets	2,944		16,953		226,890		—			246,787
Net property and equipment	—		151,331		1,375,173		—			1,526,504
Investment in subsidiaries	1,083,542		—		75,585		(1,159,127		)	—
Third-party long-term assets	—		—		3,785		—			3,785
Total assets	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	1,679	$	385,885	$	(387,564	)	$	—
Third-party current liabilities	8,640		17,753		185,791		—			212,184
Senior unsecured notes payable	573,988		—		—		—			573,988
Other third-party long-term liabilities	—		639		27,894		—			28,533
Total equity attributable to Matador Resources Company	889,743		75,584		1,083,542		(1,159,127		)	889,742
Non-controlling interest in subsidiaries	—		72,629		—		—			72,629
Total liabilities and equity	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076

Condensed Consolidating Balance Sheet December 31, 2016
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	316,791	$	3,571	$	12,091	$	(332,453	)	$	—
Third-party current assets	101,102		4,242		173,838		—			279,182
Net property and equipment	33		113,107		1,071,385		—			1,184,525
Investment in subsidiaries	856,762		—		90,275		(947,037		)	—
Third-party long-term assets	—		—		958		—			958
Total assets	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	12,091	$	320,362	$	(332,453	)	$	—
Third-party current liabilities	9,265		16,632		143,608		—			169,505
Senior unsecured notes payable	573,924		—		—		—			573,924
Other third-party long-term liabilities	1,374		602		27,815		—			29,791
Total equity attributable to Matador Resources Company	690,125		90,275		856,762		(947,037		)	690,125
Non-controlling interest in subsidiaries	—		1,320		—		—			1,320
Total liabilities and equity	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	11,274		$	127,198	$	(8,861	)	$	129,611
Total expenses	1,586			4,814			93,083		(8,861		)	90,622
Operating (loss) income	(1,586		)	6,460			34,115		—			38,989
Net gain on asset sales and inventory impairment	—			—			—		—			—
Interest expense	(9,224		)	—			—		—			(9,224		)
Other income	(27		)	26			1,923		—			1,922
Earnings in subsidiaries	39,228			—			3,244		(42,472		)	—
Income before income taxes	28,391			6,486			39,282		(42,472		)	31,687
Total income tax (benefit) provision	(118		)	64			54		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(3,178		)	—		—			(3,178		)
Net income attributable to Matador Resources Company shareholders	$	28,509		$	3,244		$	39,228	$	(42,472	)	$	28,509

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	3,210		$	44,778		$	(1,894	)	$	46,094
Total expenses	1,032			1,244			146,323			(1,894		)	146,705
Operating (loss) income	(1,032		)	1,966			(101,545		)	—			(100,611		)
Net gain on asset sales and inventory impairment	—			—			1,002			—			1,002
Interest expense	(6,167		)	—			—			—			(6,167		)
Other income	—			—			29			—			29
(Loss) earnings in subsidiaries	(98,672		)	—			1,842			96,830			—
(Loss) income before income taxes	(105,871		)	1,966			(98,672		)	96,830			(105,747		)
Total income tax (benefit) provision	(18		)	18			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(106		)	—			—			(106		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(105,853	)	$	1,842		$	(98,672	)	$	96,830		$	(105,853	)

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	20,937		$	259,846	$	(16,358	)	$	264,425
Total expenses	2,846			8,682			175,987		(16,358		)	171,157
Operating (loss) income	(2,846		)	12,255			83,859		—			93,268
Net gain on asset sales and inventory impairment	—			—			7		—			7
Interest expense	(17,679		)	—			—		—			(17,679		)
Other income	—			26			1,965		—			1,991
Earnings in subsidiaries	92,900			—			7,069		(99,969		)	—
Income before income taxes	72,375			12,281			92,900		(99,969		)	77,587
Total income tax (benefit) provision	(118		)	118			—		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(5,094		)	—		—			(5,094		)
Net income attributable to Matador Resources Company shareholders	$	72,493		$	7,069		$	92,900	$	(99,969	)	$	72,493

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	4,527		$	88,825		$	(2,635	)	$	90,717
Total expenses	2,967			2,377			290,248			(2,635		)	292,957
Operating (loss) income	(2,967		)	2,150			(201,423		)	—			(202,240		)
Net gain on asset sales and inventory impairment	—			—			2,067			—			2,067
Interest expense	(13,365		)	—			—			—			(13,365		)
Other income	—			—			124			—			124
(Loss) earnings in subsidiaries	(197,200		)	—			2,032			195,168			—
Income before income taxes	(213,532		)	2,150			(197,200		)	195,168			(213,414		)
Total income tax (benefit) provision	(25		)	25			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(93		)	—			—			(93		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(213,507	)	$	2,032		$	(197,200	)	$	195,168		$	(213,507	)

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(98,583	)	$	1,566		$	218,259		$	—		$	121,242
Net cash provided by (used in) investing activities	33			(51,580		)	(198,051		)	(133,880		)	(383,478		)
Net cash provided by (used in) financing activities	—			47,707			(769		)	133,880			180,818
(Decrease) increase in cash	(98,550		)	(2,307		)	19,439			—			(81,418		)
Cash at beginning of period	99,795			2,307			110,782			—			212,884
Cash at end of period	$	1,245		$	—		$	130,221		$	—		$	131,466

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(24,519	)	$	(6,198	)	$	80,317		$	—		$	49,600
Net cash used in investing activities	(117,086		)	(44,074		)	(172,108		)	167,236			(166,032		)
Net cash provided by financing activities	141,582			50,150			116,077			(167,236		)	140,573
(Decrease) increase in cash	(23		)	(122		)	24,286			—			24,141
Cash at beginning of period	80			186			16,466			—			16,732
Cash at end of period	$	57		$	64		$	40,752		$	—		$	40,873

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Income Taxes

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The Company’s deferred tax assets exceeded its deferred tax liabilities at June 30, 2017 due to the deferred tax assets generated by the full-cost ceiling impairment charges recorded in prior periods; as a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015. The Company retained a full valuation allowance at June 30, 2017 due to uncertainties regarding the future realization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized.

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

In February 2017, the Company granted awards of 228,174 shares of restricted stock and options to purchase 590,128 shares of the Company’s common stock at an exercise price of $27.26 per share to certain of its employees. The fair value of these awards was approximately $12.4 million. All of these awards vest ratably over three years. In February 2017, the Company also granted awards of 174,561 shares of restricted stock and options to purchase 444,491 shares of the Company’s common stock at an exercise price of $26.86 per share to certain of its employees. The fair value of these awards was approximately $9.3 million. All of these awards vest ratably over three years.

In June 2017, the Company granted an employee an award of 87,757 shares of common stock that vested immediately on the grant date. The fair value of this award was approximately $2.1 million. In June 2017, the Company also accelerated the expense for 97,797 restricted stock units issued to directors and outstanding prior to June 2017, resulting from a change in the vesting schedule applicable to equity awards granted to the Company’s directors. The total expense associated with these restricted stock units recognized in the three months ended June 30, 2017 was approximately $1.5 million.

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Derivative Financial Instruments

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

At June 30, 2017, the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2017 and 2018.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2017.

Commodity	Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)
Oil	07/01/2017 - 12/31/2017	2,460,000	$	45.17	$	55.75	$	4,365
Oil	01/01/2018 - 12/31/2018	1,920,000	$	43.91	$	63.44	4,990
Natural Gas	07/01/2017 - 12/31/2017	12,540,000	$	2.51	$	3.60	(500		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	12
Total open derivative financial instruments							$	8,867

These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its interim unaudited condensed consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets
June 30, 2017
Current assets	$	10,835		$	(3,768	)	$	7,067
Other assets	5,066			(2,074		)	2,992
Current liabilities	(4,915		)	3,723			(1,192		)
Other liabilities	(2,074		)	2,074			—
Total	$	8,912		$	(45	)	$	8,867
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the interim unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.

		Three Months Ended   June 30,						Six Months Ended   June 30,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2017			2016			2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	581		$	561		$	(1,053	)	$	6,024
Natural Gas	Revenues: Realized (loss) gain on derivatives	(23		)	1,904			(608		)	3,504
Realized gain (loss) on derivatives		558			2,465			(1,661		)	9,528
Oil	Revenues: Unrealized gain (loss) on derivatives	10,643			(19,319		)	28,422			(26,974		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	2,547			(7,306		)	5,399			(6,490		)
Unrealized gain (loss) on derivatives		13,190			(26,625		)	33,821			(33,464		)
Total		$	13,748		$	(24,160	)	$	32,160		$	(23,936	)

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Fair Value Measurements

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2017 and December 31, 2016 (in thousands).

	Fair Value Measurements at June 30, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil and natural gas derivatives	$	—	$	10,059		$	—	$	10,059
Oil and natural gas derivatives	—		(1,192		)	—		(1,192		)
Total	$	—	$	8,867		$	—	$	8,867

	Fair Value Measurements at December 31, 2016 using
Description	Level 1		Level 2			Level 3		Total
Liabilities
Oil and natural gas derivatives	$	—	$	(24,954	)	$	—	$	(24,954	)
Total	$	—	$	(24,954	)	$	—	$	(24,954	)

Additional disclosures related to derivative financial instruments are provided in Note 8.

Other Fair Value Measurements

At June 30, 2017 and December 31, 2016, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities.

At June 30, 2017 and December 31, 2016, the fair value of the Notes was $592.3 million and $605.2 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Salt Water Disposal Commitments

Eagle Ford

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

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid $0.5 million and $0.8 million in processing and transportation fees under this agreement during the three months ended June 30, 2017 and 2016, respectively, and $1.0 million and $1.7 million in processing and transportation fees under this agreement during the six months ended June 30, 2017 and 2016, respectively. The future undiscounted minimum payment under this agreement as of June 30, 2017 was $0.2 million.

Delaware Basin — Loving County, Texas Natural Gas Processing

In late 2015, the Company entered into a 15-year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at June 30, 2017, the total deficiency fee required to be paid would be approximately $11.6 million. In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $3.7 million and $2.8 million in natural gas processing and gathering fees under this agreement during the three months ended June 30, 2017 and 2016, respectively, and $6.8 million and $4.7 million in natural gas processing and gathering fees under this agreement during the six months ended June 30, 2017 and 2016, respectively.The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Delaware Basin — San Mateo

In connection with the Joint Venture, effective as of February 1, 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). The Joint Venture will provide the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at June 30, 2017 was approximately $256.4 million.

Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total commitments under these agreements are $56.9 million. The subsidiary of San Mateo paid approximately $7.9 million and $9.9 million under these agreements during the three and six months ended June 30, 2017. As of June 30, 2017, the remaining obligations under these agreements were $47.0 million, which are expected to be incurred within the next year.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for two years or less. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $42.0 million at June 30, 2017.

At June 30, 2017, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $19.7 million at June 30, 2017. The Company expects these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

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Supplemental Disclosures

6 Months Ended

Jun. 30, 2017

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at June 30, 2017 and December 31, 2016 (in thousands).

	June 30, 2017		December 31, 2016
Accrued evaluated and unproved and unevaluated property costs	$	98,589	$	54,273
Accrued support equipment and facilities costs	15,596		15,139
Accrued lease operating expenses	12,613		16,009
Accrued interest on debt	8,345		6,541
Accrued asset retirement obligations	703		915
Accrued partners’ share of joint interest charges	12,479		5,572
Other	3,011		3,011
Total accrued liabilities	$	151,336	$	101,460

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2017 and 2016 (in thousands).

	Six Months Ended   June 30,
	2017			2016
Cash paid for interest expense, net of amounts capitalized	$	15,875		$	12,226
Increase in asset retirement obligations related to mineral properties	$	1,978		$	2,511
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(138	)	$	75
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	43,797		$	(3,476	)
Increase (decrease) in liabilities for support equipment and facilities	$	1,838		$	(11,565	)
Stock-based compensation expense recognized as liability	$	(339	)	$	88
(Decrease) increase in liabilities for accrued cost to issue equity	$	(343	)	$	62
Transfer of inventory from oil and natural gas properties	$	(228	)	$	474

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Segment Information

6 Months Ended

Jun. 30, 2017

Segment Reporting [Abstract]

SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. As of February 17, 2017, substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 3).

The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”

	Exploration and Production							Consolidations and Eliminations			Consolidated Company
			Midstream		Corporate
Three Months Ended June 30, 2017
Oil and natural gas revenues	$	113,387	$	377	$	—		$	—		$	113,764
Midstream services revenues	—		11,367		—			(9,268		)	2,099
Realized gain on derivatives	558		—		—			—			558
Unrealized gain on derivatives	13,190		—		—			—			13,190
Expenses(1)	78,078		5,960		15,852			(9,268		)	90,622
Operating income (loss)(2)	$	49,057	$	5,784	$	(15,852	)	$	—		$	38,989
Total assets	$	1,436,678	$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	165,583	$	27,347	$	1,752		$	—		$	194,682

_____________________

(1) Includes depletion, depreciation and amortization expenses of $39.6 million and $1.3 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.4 million.

(2) Includes $3.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $13.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Three Months Ended June 30, 2016
Oil and natural gas revenues	$	68,864		$	472	$	—		$	—		$	69,336
Midstream services revenues	—			3,469		—			(2,551		)	918
Realized gain on derivatives	2,465			—		—			—			2,465
Unrealized loss on derivatives	(26,625		)	—		—			—			(26,625		)
Expenses(1)	134,338			1,562		13,356			(2,551		)	146,705
Operating (loss) income(2)	$	(89,634	)	$	2,379	$	(13,356	)	$	—		$	(100,611	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	97,309		$	11,192	$	2,328		$	—		$	110,829

_____________________

(1) Includes depletion, depreciation and amortization expenses of $30.6 million and $0.5 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $78.2 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.2 million.

(2) Includes $106,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2017
Oil and natural gas revenues	$	227,552		$	1,059	$	—		$	—		$	228,611
Midstream services revenues	—			20,983		—			(17,329		)	3,654
Realized loss on derivatives	(1,661		)	—		—			—			(1,661		)
Unrealized gain on derivatives	33,821			—		—			—			33,821
Expenses(1)	146,416			10,462		31,608			(17,329		)	171,157
Operating income (loss)(2)	$	113,296		$	11,580	$	(31,608	)	$	—		$	93,268
Total assets	$	1,436,678		$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	373,956		$	40,227	$	3,216		$	—		$	417,399

_____________________

(1) Includes depletion, depreciation and amortization expenses of $72.1 million and $2.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.

(2) Includes $5.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $18.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2016
Oil and natural gas revenues	$	112,672		$	590	$	—		$	—		$	113,262
Midstream services revenues	—			5,560		—			(4,169		)	1,391
Realized gain on derivatives	9,528			—		—			—			9,528
Unrealized loss on derivatives	(33,464		)	—		—			—			(33,464		)
Expenses(1)	267,365			3,096		26,665			(4,169		)	292,957
Operating (loss) income(2)	$	(178,629	)	$	3,054	$	(26,665	)	$	—		$	(202,240	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	162,116		$	32,250	$	3,582		$	—		$	197,948

_____________________

(1) Includes depletion, depreciation and amortization expenses of $58.9 million and $1.0 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $158.6 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.3 million.

(2) Includes $93,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

The interim unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Annual Report”) filed with the SEC. The Company consolidates certain subsidiaries and joint ventures that are less than wholly owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less than wholly owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments, consisting only of normal, recurring adjustments, which are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of June 30, 2017. Amounts as of December 31, 2016 are derived from the Company’s audited consolidated financial statements in the Annual Report.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Reclassifications

Reclassifications

Certain reclassifications have been made to the prior periods’ financial statements to conform to the current period presentation.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Revenue from Contracts with Customers.In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company expects to adopt the new guidance effective January 1, 2018 using the modified approach. The Company is evaluating the new guidance, including (i) identification of revenue streams and (ii) review of contracts and procedures currently in place.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842),which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The update should be applied using a retrospective transition method to each period presented. The Company believes that the impact of the adoption of this ASU will change the presentation of its beginning and ending cash balances on its Consolidated Statements of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing activities on its Consolidated Statements of Cash Flows.

Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted. Entities are required to apply guidance prospectively upon adoption. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Property and Equipment

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For the three and six months ended June 30, 2017, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties; no impairment charge was necessary. However, due primarily to declines in oil and natural gas prices in early 2016, the capitalized costs of oil and natural gas properties exceeded the cost center ceiling for the three and six months ended June 30, 2016, and as a result, the Company recorded impairment charges to its net capitalized costs of $78.2 million and $158.6 million, respectively, in its interim unaudited condensed consolidated statements of operations.

Earnings (Loss) Per Common Share

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share

The following table sets forth the computation of diluted weighted average common shares outstanding for the three and six months ended June 30, 2017 and 2016 (in thousands).

	Three Months Ended   June 30,		Six Months Ended   June 30,
	2017	2016	2017	2016
Weighted average common shares outstanding
Basic	100,211	92,346	100,005	88,826
Dilutive effect of options and restricted stock units	16	—	450	—
Diluted weighted average common shares outstanding	100,227	92,346	100,455	88,826

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of changes in Company's asset retirement obligations

The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2017 (in thousands).

Beginning asset retirement obligations	$	20,640
Liabilities incurred during period	1,222
Liabilities settled during period	(176		)
Revisions in estimated cash flows	794
Accretion expense	614
Ending asset retirement obligations	23,094
Less: current asset retirement obligations(1)	(703		)
Long-term asset retirement obligations	$	22,391

 _______________

(1) Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2017.

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Debt (Tables)

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Condensed Balance Sheet

The following presents condensed consolidating financial information on an issuer (Matador), Non-Guarantor Subsidiaries, Guarantor Subsidiaries and consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheet June 30, 2017
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	385,885	$	—	$	1,679	$	(387,564	)	$	—
Third-party current assets	2,944		16,953		226,890		—			246,787
Net property and equipment	—		151,331		1,375,173		—			1,526,504
Investment in subsidiaries	1,083,542		—		75,585		(1,159,127		)	—
Third-party long-term assets	—		—		3,785		—			3,785
Total assets	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	1,679	$	385,885	$	(387,564	)	$	—
Third-party current liabilities	8,640		17,753		185,791		—			212,184
Senior unsecured notes payable	573,988		—		—		—			573,988
Other third-party long-term liabilities	—		639		27,894		—			28,533
Total equity attributable to Matador Resources Company	889,743		75,584		1,083,542		(1,159,127		)	889,742
Non-controlling interest in subsidiaries	—		72,629		—		—			72,629
Total liabilities and equity	$	1,472,371	$	168,284	$	1,683,112	$	(1,546,691	)	$	1,777,076

Condensed Consolidating Balance Sheet December 31, 2016
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	316,791	$	3,571	$	12,091	$	(332,453	)	$	—
Third-party current assets	101,102		4,242		173,838		—			279,182
Net property and equipment	33		113,107		1,071,385		—			1,184,525
Investment in subsidiaries	856,762		—		90,275		(947,037		)	—
Third-party long-term assets	—		—		958		—			958
Total assets	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	12,091	$	320,362	$	(332,453	)	$	—
Third-party current liabilities	9,265		16,632		143,608		—			169,505
Senior unsecured notes payable	573,924		—		—		—			573,924
Other third-party long-term liabilities	1,374		602		27,815		—			29,791
Total equity attributable to Matador Resources Company	690,125		90,275		856,762		(947,037		)	690,125
Non-controlling interest in subsidiaries	—		1,320		—		—			1,320
Total liabilities and equity	$	1,274,688	$	120,920	$	1,348,547	$	(1,279,490	)	$	1,464,665

Condensed Income Statement

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	11,274		$	127,198	$	(8,861	)	$	129,611
Total expenses	1,586			4,814			93,083		(8,861		)	90,622
Operating (loss) income	(1,586		)	6,460			34,115		—			38,989
Net gain on asset sales and inventory impairment	—			—			—		—			—
Interest expense	(9,224		)	—			—		—			(9,224		)
Other income	(27		)	26			1,923		—			1,922
Earnings in subsidiaries	39,228			—			3,244		(42,472		)	—
Income before income taxes	28,391			6,486			39,282		(42,472		)	31,687
Total income tax (benefit) provision	(118		)	64			54		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(3,178		)	—		—			(3,178		)
Net income attributable to Matador Resources Company shareholders	$	28,509		$	3,244		$	39,228	$	(42,472	)	$	28,509

Condensed Consolidating Statement of Operations For the Three Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	3,210		$	44,778		$	(1,894	)	$	46,094
Total expenses	1,032			1,244			146,323			(1,894		)	146,705
Operating (loss) income	(1,032		)	1,966			(101,545		)	—			(100,611		)
Net gain on asset sales and inventory impairment	—			—			1,002			—			1,002
Interest expense	(6,167		)	—			—			—			(6,167		)
Other income	—			—			29			—			29
(Loss) earnings in subsidiaries	(98,672		)	—			1,842			96,830			—
(Loss) income before income taxes	(105,871		)	1,966			(98,672		)	96,830			(105,747		)
Total income tax (benefit) provision	(18		)	18			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(106		)	—			—			(106		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(105,853	)	$	1,842		$	(98,672	)	$	96,830		$	(105,853	)

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	20,937		$	259,846	$	(16,358	)	$	264,425
Total expenses	2,846			8,682			175,987		(16,358		)	171,157
Operating (loss) income	(2,846		)	12,255			83,859		—			93,268
Net gain on asset sales and inventory impairment	—			—			7		—			7
Interest expense	(17,679		)	—			—		—			(17,679		)
Other income	—			26			1,965		—			1,991
Earnings in subsidiaries	92,900			—			7,069		(99,969		)	—
Income before income taxes	72,375			12,281			92,900		(99,969		)	77,587
Total income tax (benefit) provision	(118		)	118			—		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(5,094		)	—		—			(5,094		)
Net income attributable to Matador Resources Company shareholders	$	72,493		$	7,069		$	92,900	$	(99,969	)	$	72,493

Condensed Consolidating Statement of Operations For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	4,527		$	88,825		$	(2,635	)	$	90,717
Total expenses	2,967			2,377			290,248			(2,635		)	292,957
Operating (loss) income	(2,967		)	2,150			(201,423		)	—			(202,240		)
Net gain on asset sales and inventory impairment	—			—			2,067			—			2,067
Interest expense	(13,365		)	—			—			—			(13,365		)
Other income	—			—			124			—			124
(Loss) earnings in subsidiaries	(197,200		)	—			2,032			195,168			—
Income before income taxes	(213,532		)	2,150			(197,200		)	195,168			(213,414		)
Total income tax (benefit) provision	(25		)	25			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(93		)	—			—			(93		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(213,507	)	$	2,032		$	(197,200	)	$	195,168		$	(213,507	)

Condensed Cash Flow Statement

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(98,583	)	$	1,566		$	218,259		$	—		$	121,242
Net cash provided by (used in) investing activities	33			(51,580		)	(198,051		)	(133,880		)	(383,478		)
Net cash provided by (used in) financing activities	—			47,707			(769		)	133,880			180,818
(Decrease) increase in cash	(98,550		)	(2,307		)	19,439			—			(81,418		)
Cash at beginning of period	99,795			2,307			110,782			—			212,884
Cash at end of period	$	1,245		$	—		$	130,221		$	—		$	131,466

Condensed Consolidating Statement of Cash Flows For the Six Months Ended June 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(24,519	)	$	(6,198	)	$	80,317		$	—		$	49,600
Net cash used in investing activities	(117,086		)	(44,074		)	(172,108		)	167,236			(166,032		)
Net cash provided by financing activities	141,582			50,150			116,077			(167,236		)	140,573
(Decrease) increase in cash	(23		)	(122		)	24,286			—			24,141
Cash at beginning of period	80			186			16,466			—			16,732
Cash at end of period	$	57		$	64		$	40,752		$	—		$	40,873

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Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2017

Open Option Contracts Written [Line Items]

Summary of gross asset balances of derivative instruments

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets
June 30, 2017
Current assets	$	10,835		$	(3,768	)	$	7,067
Other assets	5,066			(2,074		)	2,992
Current liabilities	(4,915		)	3,723			(1,192		)
Other liabilities	(2,074		)	2,074			—
Total	$	8,912		$	(45	)	$	8,867
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)

Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the interim unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.

		Three Months Ended   June 30,						Six Months Ended   June 30,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2017			2016			2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	581		$	561		$	(1,053	)	$	6,024
Natural Gas	Revenues: Realized (loss) gain on derivatives	(23		)	1,904			(608		)	3,504
Realized gain (loss) on derivatives		558			2,465			(1,661		)	9,528
Oil	Revenues: Unrealized gain (loss) on derivatives	10,643			(19,319		)	28,422			(26,974		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	2,547			(7,306		)	5,399			(6,490		)
Unrealized gain (loss) on derivatives		13,190			(26,625		)	33,821			(33,464		)
Total		$	13,748		$	(24,160	)	$	32,160		$	(23,936	)

Open costless collar contracts

Open Option Contracts Written [Line Items]

Summary of contracts for oil and natural gas

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2017.

Commodity	Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)
Oil	07/01/2017 - 12/31/2017	2,460,000	$	45.17	$	55.75	$	4,365
Oil	01/01/2018 - 12/31/2018	1,920,000	$	43.91	$	63.44	4,990
Natural Gas	07/01/2017 - 12/31/2017	12,540,000	$	2.51	$	3.60	(500		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	12
Total open derivative financial instruments							$	8,867

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Summary of the valuation of the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2017 and December 31, 2016 (in thousands).

	Fair Value Measurements at June 30, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil and natural gas derivatives	$	—	$	10,059		$	—	$	10,059
Oil and natural gas derivatives	—		(1,192		)	—		(1,192		)
Total	$	—	$	8,867		$	—	$	8,867

	Fair Value Measurements at December 31, 2016 using
Description	Level 1		Level 2			Level 3		Total
Liabilities
Oil and natural gas derivatives	$	—	$	(24,954	)	$	—	$	(24,954	)
Total	$	—	$	(24,954	)	$	—	$	(24,954	)

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Supplemental Disclosures (Tables)

6 Months Ended

Jun. 30, 2017

Supplemental Disclosures [Abstract]

Summary of current accrued liabilities

The following table summarizes the Company’s current accrued liabilities at June 30, 2017 and December 31, 2016 (in thousands).

	June 30, 2017		December 31, 2016
Accrued evaluated and unproved and unevaluated property costs	$	98,589	$	54,273
Accrued support equipment and facilities costs	15,596		15,139
Accrued lease operating expenses	12,613		16,009
Accrued interest on debt	8,345		6,541
Accrued asset retirement obligations	703		915
Accrued partners’ share of joint interest charges	12,479		5,572
Other	3,011		3,011
Total accrued liabilities	$	151,336	$	101,460

Supplemental disclosures of cash flow information

The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2017 and 2016 (in thousands).

	Six Months Ended   June 30,
	2017			2016
Cash paid for interest expense, net of amounts capitalized	$	15,875		$	12,226
Increase in asset retirement obligations related to mineral properties	$	1,978		$	2,511
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(138	)	$	75
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	43,797		$	(3,476	)
Increase (decrease) in liabilities for support equipment and facilities	$	1,838		$	(11,565	)
Stock-based compensation expense recognized as liability	$	(339	)	$	88
(Decrease) increase in liabilities for accrued cost to issue equity	$	(343	)	$	62
Transfer of inventory from oil and natural gas properties	$	(228	)	$	474

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2017

Segment Reporting [Abstract]

Selected financial information for segments

The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”

	Exploration and Production							Consolidations and Eliminations			Consolidated Company
			Midstream		Corporate
Three Months Ended June 30, 2017
Oil and natural gas revenues	$	113,387	$	377	$	—		$	—		$	113,764
Midstream services revenues	—		11,367		—			(9,268		)	2,099
Realized gain on derivatives	558		—		—			—			558
Unrealized gain on derivatives	13,190		—		—			—			13,190
Expenses(1)	78,078		5,960		15,852			(9,268		)	90,622
Operating income (loss)(2)	$	49,057	$	5,784	$	(15,852	)	$	—		$	38,989
Total assets	$	1,436,678	$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	165,583	$	27,347	$	1,752		$	—		$	194,682

_____________________

(1) Includes depletion, depreciation and amortization expenses of $39.6 million and $1.3 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.4 million.

(2) Includes $3.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $13.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Three Months Ended June 30, 2016
Oil and natural gas revenues	$	68,864		$	472	$	—		$	—		$	69,336
Midstream services revenues	—			3,469		—			(2,551		)	918
Realized gain on derivatives	2,465			—		—			—			2,465
Unrealized loss on derivatives	(26,625		)	—		—			—			(26,625		)
Expenses(1)	134,338			1,562		13,356			(2,551		)	146,705
Operating (loss) income(2)	$	(89,634	)	$	2,379	$	(13,356	)	$	—		$	(100,611	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	97,309		$	11,192	$	2,328		$	—		$	110,829

_____________________

(1) Includes depletion, depreciation and amortization expenses of $30.6 million and $0.5 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $78.2 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.2 million.

(2) Includes $106,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2017
Oil and natural gas revenues	$	227,552		$	1,059	$	—		$	—		$	228,611
Midstream services revenues	—			20,983		—			(17,329		)	3,654
Realized loss on derivatives	(1,661		)	—		—			—			(1,661		)
Unrealized gain on derivatives	33,821			—		—			—			33,821
Expenses(1)	146,416			10,462		31,608			(17,329		)	171,157
Operating income (loss)(2)	$	113,296		$	11,580	$	(31,608	)	$	—		$	93,268
Total assets	$	1,436,678		$	192,889	$	147,509		$	—		$	1,777,076
Capital expenditures(3)	$	373,956		$	40,227	$	3,216		$	—		$	417,399

_____________________

(1) Includes depletion, depreciation and amortization expenses of $72.1 million and $2.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.7 million.

(2) Includes $5.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Includes $18.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production								Consolidations and Eliminations			Consolidated Company
				Midstream		Corporate
Six Months Ended June 30, 2016
Oil and natural gas revenues	$	112,672		$	590	$	—		$	—		$	113,262
Midstream services revenues	—			5,560		—			(4,169		)	1,391
Realized gain on derivatives	9,528			—		—			—			9,528
Unrealized loss on derivatives	(33,464		)	—		—			—			(33,464		)
Expenses(1)	267,365			3,096		26,665			(4,169		)	292,957
Operating (loss) income(2)	$	(178,629	)	$	3,054	$	(26,665	)	$	—		$	(202,240	)
Total assets	$	927,557		$	106,425	$	52,106		$	—		$	1,086,088
Capital expenditures	$	162,116		$	32,250	$	3,582		$	—		$	197,948

_____________________

(1) Includes depletion, depreciation and amortization expenses of $58.9 million and $1.0 million for the exploration and production and midstream segments, respectively, and full-cost ceiling impairment expenses of $158.6 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $0.3 million.

(2) Includes $93,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Summary of Significant Accounting Policies (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Third-party midstream services revenues	$ 2,099	$ 918	$ 3,654	$ 1,391
Plant and other midstream services operating	2,942	1,061	$ 5,283	2,088
Discount rate present value of future revenue from proved oil and gas reserves			10.00%
Full-cost ceiling impairment	0	78,171	$ 0	158,633
Capitalized general and administrative costs	5,200	4,000	10,800	6,000
Capitalized interest expense	$ 1,900	1,700	$ 3,200	2,200
Reclassification from Other Income to Third-Party Midstream Services Revenue [Member] | Restatement Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Third-party midstream services revenues		900		1,400
Reclassification from Lease Operating Expenses to Plant and Other Midstream Services Operating Expenses [Member] | Restatement Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Plant and other midstream services operating		$ 1,100		$ 2,100

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Summary of Significant Accounting Policies (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average common shares outstanding for basic earnings (loss) per share	100,211	92,346	100,005	88,826
Dilutive effect of options and restricted stock units	16	0	450	0
Diluted weighted average common shares outstanding	100,227	92,346	100,455	88,826
Stock Option
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from earnings per share calculations because their effects would be anti-dilutive				2,900
Restricted Stock Units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from earnings per share calculations because their effects would be anti-dilutive				100
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from earnings per share calculations because their effects would be anti-dilutive				900

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Business Combination (Details) $ in Thousands		6 Months Ended
	Feb. 17, 2017 USD ($) well	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)
Business Acquisition [Line Items]
Contributions related to formation of Joint Venture		$ 171,500	$ 0
Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Business Acquisition [Line Items]
Ownership percentage	51.00%	51.00%
Deferred performance incentives	$ 73,500
Deferred performance incentives term	5 years
Cash contributed to joint venture	$ 5,100
Additional cost commitment	$ 140,000
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Rustler Breaks Asset Area [Member]
Business Acquisition [Line Items]
Number of wells contributed to joint venture | well	1
Term of contractual obligation	15 years
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Wolf Asset Area [Member]
Business Acquisition [Line Items]
Number of wells contributed to joint venture | well	3
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Rustler Breaks and Wolf Asset Area [Member]
Business Acquisition [Line Items]
Term of contractual obligation	15 years
Five Point [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Business Acquisition [Line Items]
Ownership percentage	49.00%
Payments to acquire interest in joint venture	$ 176,400
Contributions related to formation of Joint Venture	$ 171,500

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations				$ 20,640
Liabilities incurred during period				1,222
Liabilities settled during period				(176)
Revisions in estimated cash flows				794
Accretion expense		$ 314	$ 289	614	$ 552
Ending asset retirement obligations		23,094		23,094
Less: current asset retirement obligations	[1]	(703)		(703)
Long-term asset retirement obligations		$ 22,391		$ 22,391		$ 19,725

[1] Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2017.

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Debt (Details) - USD ($)		6 Months Ended
	May 24, 2017	Jun. 30, 2017	Aug. 02, 2017	Apr. 28, 2017	Feb. 17, 2017	Dec. 31, 2016	Dec. 09, 2016	Apr. 14, 2015
Revolving Credit Agreement (Textual) [Abstract]
Senior unsecured notes		$ 573,988,000				$ 573,924,000
Deferred loan costs						$ 1,100,000
Repay deficit in agreement period		6 months
Third Amended Credit Agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Amended maximum borrowing capacity		$ 500,000,000
Senior Notes | Senior Notes Due 2023
Revolving Credit Agreement (Textual) [Abstract]
Senior unsecured notes		$ 575,000,000					$ 175,000,000	$ 400,000,000
Interest rate	6.875%	6.875%					6.875%	6.875%
Debt exchanged	$ 175,000,000.0
Subsequent Event [Member] | Senior Notes | Senior Notes Due 2023
Revolving Credit Agreement (Textual) [Abstract]
Senior unsecured notes			$ 575,000,000.0
Interest rate			6.875%
Revolving Credit Facility [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under Credit Agreement		$ 0
Maximum borrowing capacity		400,000,000		$ 450,000,000
Revolving Credit Facility [Member] | Subsequent Event [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under Credit Agreement			$ 0
Letter of Credit [Member]
Revolving Credit Agreement (Textual) [Abstract]
Outstanding letters of credit		$ 800,000
Letter of Credit [Member] | Subsequent Event [Member]
Revolving Credit Agreement (Textual) [Abstract]
Outstanding letters of credit			$ 800,000
Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Revolving Credit Agreement (Textual) [Abstract]
Ownership percentage		51.00%			51.00%

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Debt (Details 2) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	$ 0	$ 0
Third-party current assets	246,787	279,182
Net property and equipment	1,526,504	1,184,525
Investment in subsidiaries	0	0
Third-party long-term assets	3,785	958
Total assets	1,777,076	1,464,665	$ 1,086,088
Intercompany payable	0	0
Third-party current liabilities	212,184	169,505
Senior unsecured notes payable	573,988	573,924
Other third-party long-term liabilities	28,533	29,791
Total equity attributable to Matador Resources Company	889,742	690,125
Non-controlling interest in subsidiaries	72,629	1,320
Total liabilities and shareholders’ equity	1,777,076	1,464,665
Eliminating Entries [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	(387,564)	(332,453)
Third-party current assets	0	0
Net property and equipment	0	0
Investment in subsidiaries	(1,159,127)	(947,037)
Third-party long-term assets	0	0
Total assets	(1,546,691)	(1,279,490)
Intercompany payable	(387,564)	(332,453)
Third-party current liabilities	0	0
Senior unsecured notes payable	0	0
Other third-party long-term liabilities	0	0
Total equity attributable to Matador Resources Company	(1,159,127)	(947,037)
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	(1,546,691)	(1,279,490)
Matador [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	385,885	316,791
Third-party current assets	2,944	101,102
Net property and equipment	0	33
Investment in subsidiaries	1,083,542	856,762
Third-party long-term assets	0	0
Total assets	1,472,371	1,274,688
Intercompany payable	0	0
Third-party current liabilities	8,640	9,265
Senior unsecured notes payable	573,988	573,924
Other third-party long-term liabilities	0	1,374
Total equity attributable to Matador Resources Company	889,743	690,125
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	1,472,371	1,274,688
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	0	3,571
Third-party current assets	16,953	4,242
Net property and equipment	151,331	113,107
Investment in subsidiaries	0	0
Third-party long-term assets	0	0
Total assets	168,284	120,920
Intercompany payable	1,679	12,091
Third-party current liabilities	17,753	16,632
Senior unsecured notes payable	0	0
Other third-party long-term liabilities	639	602
Total equity attributable to Matador Resources Company	75,584	90,275
Non-controlling interest in subsidiaries	72,629	1,320
Total liabilities and shareholders’ equity	168,284	120,920
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivable	1,679	12,091
Third-party current assets	226,890	173,838
Net property and equipment	1,375,173	1,071,385
Investment in subsidiaries	75,585	90,275
Third-party long-term assets	3,785	958
Total assets	1,683,112	1,348,547
Intercompany payable	385,885	320,362
Third-party current liabilities	185,791	143,608
Senior unsecured notes payable	0	0
Other third-party long-term liabilities	27,894	27,815
Total equity attributable to Matador Resources Company	1,083,542	856,762
Non-controlling interest in subsidiaries	0	0
Total liabilities and shareholders’ equity	$ 1,683,112	$ 1,348,547

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Debt (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 129,611	$ 46,094	$ 264,425	$ 90,717
Total expenses	90,622	146,705	171,157	292,957
Operating income (loss)	38,989	(100,611)	93,268	(202,240)
Net gain on asset sales and inventory impairment	0	1,002	7	2,067
Interest expense	(9,224)	(6,167)	(17,679)	(13,365)
Other income	1,922	29	1,991	124
Earnings in subsidiaries	0	0	0	0
Net income (loss)	31,687	(105,747)	77,587	(213,414)
Total income tax (benefit) provision	0	0	0	0
Net income attributable to non-controlling interest in subsidiaries	(3,178)	(106)	(5,094)	(93)
Net income (loss) attributable to Matador Resources Company shareholders	28,509	(105,853)	72,493	(213,507)
Eliminating Entries [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	(8,861)	(1,894)	(16,358)	(2,635)
Total expenses	(8,861)	(1,894)	(16,358)	(2,635)
Net gain on asset sales and inventory impairment	0	0	0	0
Earnings in subsidiaries	(42,472)	96,830	(99,969)	195,168
Net income (loss)	(42,472)	96,830	(99,969)	195,168
Total income tax (benefit) provision	0	0	0	0
Net income attributable to non-controlling interest in subsidiaries	0	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	(42,472)	96,830	(99,969)	195,168
Matador [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total expenses	1,586	1,032	2,846	2,967
Operating income (loss)	(1,586)	(1,032)	(2,846)	(2,967)
Net gain on asset sales and inventory impairment	0	0
Interest expense	(9,224)	(6,167)	(17,679)	(13,365)
Other income	(27)
Earnings in subsidiaries	39,228	(98,672)	92,900	(197,200)
Net income (loss)	28,391	(105,871)	72,375	(213,532)
Total income tax (benefit) provision	(118)	(18)	(118)	(25)
Net income attributable to non-controlling interest in subsidiaries	0	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	28,509	(105,853)	72,493	(213,507)
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	11,274	3,210	20,937	4,527
Total expenses	4,814	1,244	8,682	2,377
Operating income (loss)	6,460	1,966	12,255	2,150
Net gain on asset sales and inventory impairment	0	0	0	0
Other income	26		26
Earnings in subsidiaries	0	0	0	0
Net income (loss)	6,486	1,966	12,281	2,150
Total income tax (benefit) provision	64	18	118	25
Net income attributable to non-controlling interest in subsidiaries	(3,178)	(106)	(5,094)	(93)
Net income (loss) attributable to Matador Resources Company shareholders	3,244	1,842	7,069	2,032
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	127,198	44,778	259,846	88,825
Total expenses	93,083	146,323	175,987	290,248
Operating income (loss)	34,115	(101,545)	83,859	(201,423)
Net gain on asset sales and inventory impairment	0	1,002	7	2,067
Other income	1,923	29	1,965	124
Earnings in subsidiaries	3,244	1,842	7,069	2,032
Net income (loss)	39,282	(98,672)	92,900	(197,200)
Total income tax (benefit) provision	54	0	0	0
Net income attributable to non-controlling interest in subsidiaries	0	0	0	0
Net income (loss) attributable to Matador Resources Company shareholders	$ 39,228	$ (98,672)	$ 92,900	$ (197,200)

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Debt (Details 4) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 121,242	$ 49,600
Net cash provided by (used in) investing activities	(383,478)	(166,032)
Net cash provided by (used in) financing activities	180,818	140,573
(Decrease) increase in cash	(81,418)	24,141
Cash at beginning of period	212,884	16,732
Cash at end of period	131,466	40,873
Eliminating Entries [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	0	0
Net cash provided by (used in) investing activities	(133,880)	167,236
Net cash provided by (used in) financing activities	133,880	(167,236)
(Decrease) increase in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	0	0
Matador [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(98,583)	(24,519)
Net cash provided by (used in) investing activities	33	(117,086)
Net cash provided by (used in) financing activities	0	141,582
(Decrease) increase in cash	(98,550)	(23)
Cash at beginning of period	99,795	80
Cash at end of period	1,245	57
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	1,566	(6,198)
Net cash provided by (used in) investing activities	(51,580)	(44,074)
Net cash provided by (used in) financing activities	47,707	50,150
(Decrease) increase in cash	(2,307)	(122)
Cash at beginning of period	2,307	186
Cash at end of period	0	64
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	218,259	80,317
Net cash provided by (used in) investing activities	(198,051)	(172,108)
Net cash provided by (used in) financing activities	(769)	116,077
(Decrease) increase in cash	19,439	24,286
Cash at beginning of period	110,782	16,466
Cash at end of period	$ 130,221	$ 40,752

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Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions				1 Months Ended
	Jun. 01, 2017	Feb. 16, 2017	Feb. 15, 2017	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted in period		444,491	590,128
Share Price			$ 27.26
Fair value		$ 9.3	$ 12.4
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted in period		174,561	228,174
Share Price		$ 26.86
Vesting period of shares		3 years	3 years
Accelerated vesting (in shares)	97,797
Accelerated vesting compensation expense	$ 1.5
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted in period				87,757
Fair value				$ 2.1

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Derivative Financial Instruments (Details) - Open costless collar contracts $ in Thousands	Jun. 30, 2017 USD ($) MMBTU bbl $ / bbl $ / MMBTU
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability)	$ 8,867
Oil, Calculation Period 04/01/2017 - 12/31/2017
Summary of contracts for oil and natural gas
Notional Quantity (Bbl or MMBtu) | bbl	2,460,000
Weighted Average Price Floor ($/Bbl or $/MMBtu) | $ / bbl	45.17
Weighted Average Price Ceiling ($/Bbl or $/MMBtu) | $ / bbl	55.75
Fair Value of Asset (Liability)	$ 4,365
Oil, Calculation Period 01/01/2018 - 12/31/2018
Summary of contracts for oil and natural gas
Notional Quantity (Bbl or MMBtu) | bbl	1,920,000
Weighted Average Price Floor ($/Bbl or $/MMBtu) | $ / bbl	43.91
Weighted Average Price Ceiling ($/Bbl or $/MMBtu) | $ / bbl	63.44
Fair Value of Asset (Liability)	$ 4,990
Natural Gas, Calculation Period 04/01/2017 - 12/31/2017
Summary of contracts for oil and natural gas
Notional Quantity (Bbl or MMBtu) | MMBTU	12,540,000
Weighted Average Price Floor ($/Bbl or $/MMBtu) | $ / MMBTU	2.51
Weighted Average Price Ceiling ($/Bbl or $/MMBtu) | $ / MMBTU	3.60
Fair Value of Asset (Liability)	$ (500)
Natural Gas, Calculation Period 01/01/2018 - 12/31/2018
Summary of contracts for oil and natural gas
Notional Quantity (Bbl or MMBtu) | MMBTU	16,800,000
Weighted Average Price Floor ($/Bbl or $/MMBtu) | $ / MMBTU	2.58
Weighted Average Price Ceiling ($/Bbl or $/MMBtu) | $ / MMBTU	3.67
Fair Value of Asset (Liability)	$ 12

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Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Summary of gross liability balances of derivative instruments
Total	$ 8,912	$ (24,954)
Gross amounts netted in the condensed consolidated balance sheets	(45)	0
Net amounts presented in the condensed consolidated balance sheets	8,867	(24,954)
Current assets
Derivative [Line Items]
Gross amounts of recognized assets	10,835
Gross amounts netted in the condensed consolidated balance sheets	(3,768)
Oil, natural gas and natural gas liquids (NGL) derivatives	7,067
Other assets
Derivative [Line Items]
Gross amounts of recognized assets	5,066
Gross amounts netted in the condensed consolidated balance sheets	(2,074)
Oil, natural gas and natural gas liquids (NGL) derivatives	2,992
Current liabilities
Summary of gross liability balances of derivative instruments
Gross amounts of recognized liabilities	(4,915)	(24,203)
Gross amounts netted in the condensed consolidated balance sheet	3,723	0
Oil, natural gas and natural gas liquids (NGL) derivatives	(1,192)	(24,203)
Other liabilities
Summary of gross liability balances of derivative instruments
Gross amounts of recognized liabilities	(2,074)	(751)
Gross amounts netted in the condensed consolidated balance sheet	2,074	0
Oil, natural gas and natural gas liquids (NGL) derivatives	$ 0	$ (751)

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Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	$ 558	$ 2,465	$ (1,661)	$ 9,528
Unrealized gain (loss) on derivatives	13,190	(26,625)	33,821	(33,464)
Total	13,748	(24,160)	32,160	(23,936)
Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	558	2,465	(1,661)	9,528
Unrealized gain (loss) on derivatives	13,190	(26,625)	33,821	(33,464)
Oil | Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	581	561	(1,053)	6,024
Unrealized gain (loss) on derivatives	10,643	(19,319)	28,422	(26,974)
Natural Gas | Revenues
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain (loss) on derivatives	(23)	1,904	(608)	3,504
Unrealized gain (loss) on derivatives	$ 2,547	$ (7,306)	$ 5,399	$ (6,490)

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Assets (Liabilities)
Total	$ 8,912	$ (24,954)
Fair value on a recurring basis
Assets (Liabilities)
Derivative Asset	10,059	(24,954)
Derivative Liability	(1,192)
Total	8,867	(24,954)
Fair value on a recurring basis | Level 1
Assets (Liabilities)
Derivative Asset	0	0
Derivative Liability	0
Fair value on a recurring basis | Level 2
Assets (Liabilities)
Derivative Asset	10,059	(24,954)
Derivative Liability	(1,192)
Total	8,867	(24,954)
Fair value on a recurring basis | Level 3
Assets (Liabilities)
Derivative Asset	0	$ 0
Derivative Liability	$ 0

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Fair Value Measurements (Details 1) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Senior Notes Due 2023 | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of notes	$ 592.3	$ 605.2

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Commitments and Contingencies (Details) - USD ($) $ in Thousands			1 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Feb. 17, 2017	May 31, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2015
Commitments and Contingencies (Textual) [Abstract]
Natural gas processing and transportation agreement						5 years
Minimum delivery commitment to avoid paying gas deficiency fee						80.00%
Transportation and processing fee under the agreement				$ 500	$ 800	$ 1,000	$ 1,700
Drilling Rig Commitments
Commitments and Contingencies (Textual) [Abstract]
Maximum termination outstanding obligations of contracts	$ 41,974			41,974		41,974
Outside Operated Drilling Commitments
Commitments and Contingencies (Textual) [Abstract]
Maximum termination outstanding obligations of contracts	19,697			19,697		19,697
Eagle Ford Acreage Agreement [Member]
Commitments and Contingencies (Textual) [Abstract]
Future undiscounted minimum payments, minimum	200			200		200
Loving County System Agreement
Commitments and Contingencies (Textual) [Abstract]
Transportation and processing fee under the agreement				3,700	$ 2,800	6,800	$ 4,700
Agreement term								15 years
Deficiency fee required to be paid						11,600
Capital Addition Purchase Commitments [Member]
Commitments and Contingencies (Textual) [Abstract]
Remaining commitments	47,000		$ 56,900
Payment for long-term purchase commitment				7,900		$ 9,900
Term Of Old Contract Drilling Rig
Commitments and Contingencies (Textual) [Abstract]
Purchase commitment term						2 years
Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Commitments and Contingencies (Textual) [Abstract]
Contractual obligation	$ 256,400			$ 256,400		$ 256,400
Rustler Breaks and Wolf Asset Area [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Commitments and Contingencies (Textual) [Abstract]
Term of contractual obligation		15 years
Rustler Breaks Asset Area [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member]
Commitments and Contingencies (Textual) [Abstract]
Term of contractual obligation		15 years

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Supplemental Disclosures (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Supplemental Disclosures [Line Items]
Interest Paid, Net	$ 15,875	$ 12,226
Summary of current accrued liabilities
Total accrued liabilities	151,336		$ 101,460
Accrued evaluated and unproved and unevaluated property costs
Summary of current accrued liabilities
Total accrued liabilities	98,589		54,273
Accrued support equipment and facilities costs
Summary of current accrued liabilities
Total accrued liabilities	15,596		15,139
Accrued lease operating expenses
Summary of current accrued liabilities
Total accrued liabilities	12,613		16,009
Accrued interest on debt
Summary of current accrued liabilities
Total accrued liabilities	8,345		6,541
Accrued asset retirement obligations
Summary of current accrued liabilities
Total accrued liabilities	703		915
Accrued partners’ share of joint interest charges
Summary of current accrued liabilities
Total accrued liabilities	12,479		5,572
Other
Summary of current accrued liabilities
Total accrued liabilities	$ 3,011		$ 3,011

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Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Supplemental disclosures of cash flow information
Asset retirement obligations related to mineral properties	$ 1,978	$ 2,511
Asset retirement obligations related to support equipment and facilities	(138)	75
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	43,797	(3,476)
(Decrease) increase in liabilities for support equipment and facilities	1,838	(11,565)
Stock-based compensation expense recognized as liability	(339)	88
Increase (Decrease) in Liabilities for Accrued Cost to Issue Equity	(343)	62
Transfer of inventory from oil and natural gas properties	$ (228)	$ 474

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Segment Information (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) segment	Jun. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of segments | segment			2
Oil and natural gas revenues	$ 113,764,000	$ 69,336,000	$ 228,611,000	$ 113,262,000
Third-party midstream services revenues	2,099,000	918,000	3,654,000	1,391,000
Realized gain (loss) on derivatives	558,000	2,465,000	(1,661,000)	9,528,000
Unrealized gain (loss) on derivatives	13,190,000	(26,625,000)	33,821,000	(33,464,000)
Expenses	90,622,000	146,705,000	171,157,000	292,957,000
Operating Income (Loss)	38,989,000	(100,611,000)	93,268,000	(202,240,000)
Total assets	1,777,076,000	1,086,088,000	1,777,076,000	1,086,088,000	$ 1,464,665,000
Capital Expenditures	194,682,000	110,829,000	417,399,000	197,948,000
Depreciation, Depletion and Amortization	41,274,000	31,248,000	75,266,000	60,170,000
Net income attributable to non-controlling interest in subsidiaries	3,178,000	106,000	5,094,000	93,000
Impairment of Oil and Gas Properties	0	78,171,000	0	158,633,000
Corporate [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues		0	0	0
Third-party midstream services revenues	0	0	0	0
Realized gain (loss) on derivatives		0	0	0
Unrealized gain (loss) on derivatives		0	0	0
Expenses	15,852,000	13,356,000	31,608,000	26,665,000
Operating Income (Loss)	(15,852,000)	(13,356,000)	(31,608,000)	(26,665,000)
Total assets	147,509,000	52,106,000	147,509,000	52,106,000
Capital Expenditures	1,752,000	2,328,000	3,216,000	3,582,000
Depreciation, Depletion and Amortization	400,000	200,000	700,000	300,000
Eliminations [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues		0	0	0
Third-party midstream services revenues	(9,268,000)	(2,551,000)	(17,329,000)	(4,169,000)
Realized gain (loss) on derivatives		0	0	0
Unrealized gain (loss) on derivatives		0	0	0
Expenses	(9,268,000)	(2,551,000)	(17,329,000)	(4,169,000)
Total assets	0	0	0	0
Capital Expenditures	0	0	0	0
Exploration and Production Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	113,387,000	68,864,000	227,552,000	112,672,000
Third-party midstream services revenues	0	0	0	0
Realized gain (loss) on derivatives	558,000	2,465,000	(1,661,000)	9,528,000
Unrealized gain (loss) on derivatives	13,190,000	(26,625,000)	33,821,000	(33,464,000)
Expenses	78,078,000	134,338,000	146,416,000	267,365,000
Operating Income (Loss)	49,057,000	(89,634,000)	113,296,000	(178,629,000)
Total assets	1,436,678,000	927,557,000	1,436,678,000	927,557,000
Capital Expenditures	165,583,000	97,309,000	373,956,000	162,116,000
Depreciation, Depletion and Amortization	39,600,000	30,600,000	72,100,000	58,900,000
Impairment of Oil and Gas Properties		78,200,000		158,600,000
Midstream Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	377,000	472,000	1,059,000	590,000
Third-party midstream services revenues	11,367,000	3,469,000	20,983,000	5,560,000
Realized gain (loss) on derivatives		0	0	0
Unrealized gain (loss) on derivatives		0	0	0
Expenses	5,960,000	1,562,000	10,462,000	3,096,000
Operating Income (Loss)	5,784,000	2,379,000	11,580,000	3,054,000
Total assets	192,889,000	106,425,000	192,889,000	106,425,000
Capital Expenditures	27,347,000	11,192,000	40,227,000	32,250,000
Depreciation, Depletion and Amortization	1,300,000	500,000	2,500,000	1,000,000
Net income attributable to non-controlling interest in subsidiaries		$ 106,000	5,100,000	$ 93,000
Payments to Acquire Productive Assets, Noncontrolling Interest	13,400,000		$ 18,600,000
Operating Income (Loss) [Member] | Midstream Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income attributable to non-controlling interest in subsidiaries	$ 3,200,000