Document



	September 30, 2017			December 31, 2016
ASSETS
Current assets
Cash	$	20,178		$	212,884
Restricted cash	10,744			1,258
Accounts receivable
Oil and natural gas revenues	49,885			34,154
Joint interest billings	53,721			19,347
Other	5,406			5,167
Derivative instruments	60			—
Lease and well equipment inventory	4,801			3,045
Prepaid expenses and other assets	5,550			3,327
Total current assets	150,345			279,182
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,842,810			2,408,305
Unproved and unevaluated	600,803			479,736
Other property and equipment	240,924			160,795
Less accumulated depletion, depreciation and amortization	(1,987,370		)	(1,864,311		)
Net property and equipment	1,697,167			1,184,525
Other assets
Derivative instruments	285			—
Other assets	740			958
Total other assets	1,025			958
Total assets	$	1,848,537		$	1,464,665
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	13,839		$	4,674
Accrued liabilities	158,345			101,460
Royalties payable	53,639			23,988
Amounts due to affiliates	12,749			8,651
Derivative instruments	3,641			24,203
Advances from joint interest owners	4,346			1,700
Amounts due to joint ventures	4,873			4,251
Other current liabilities	663			578
Total current liabilities	252,095			169,505
Long-term liabilities
Senior unsecured notes payable	574,027			573,924
Asset retirement obligations	23,305			19,725
Derivative instruments	209			751
Amounts due to joint ventures	—			1,771
Other long-term liabilities	6,104			7,544
Total long-term liabilities	603,645			603,715
Commitments and contingencies (Note 11)
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 100,566,054 and 99,518,764 shares issued; and 100,439,595 and 99,511,931 shares outstanding, respectively	1,006			995
Additional paid-in capital	1,455,605			1,325,481
Accumulated deficit	(548,819		)	(636,351		)
Treasury stock, at cost, 126,459 and 6,833 shares, respectively	(1,589		)	—
Total Matador Resources Company shareholders’ equity	906,203			690,125
Non-controlling interest in subsidiaries	86,594			1,320
Total shareholders’ equity	992,797			691,445
Total liabilities and shareholders’ equity	$	1,848,537		$	1,464,665



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues
Oil and natural gas revenues	$	134,948		$	83,079		$	363,559		$	196,341
Third-party midstream services revenues	3,218			1,566			6,871			2,956
Realized gain (loss) on derivatives	485			885			(1,176		)	10,413
Unrealized (loss) gain on derivatives	(12,372		)	3,203			21,449			(30,261		)
Total revenues	126,279			88,733			390,703			179,449
Expenses
Production taxes, transportation and processing	15,666			12,388			40,348			30,846
Lease operating	16,689			14,605			48,486			41,300
Plant and other midstream services operating	3,096			1,449			8,379			3,537
Depletion, depreciation and amortization	47,800			30,015			123,066			90,185
Accretion of asset retirement obligations	323			276			937			828
Full-cost ceiling impairment	—			—			—			158,633
General and administrative	16,156			13,146			49,671			39,506
Total expenses	99,730			71,879			270,887			364,835
Operating income (loss)	26,549			16,854			119,816			(185,386		)
Other income (expense)
Net gain on asset sales and inventory impairment	16			1,073			23			3,140
Interest expense	(8,550		)	(6,880		)	(26,229		)	(20,244		)
Other (expense) income	(36		)	(141		)	1,956			(17		)
Total other expense	(8,570		)	(5,948		)	(24,250		)	(17,121		)
Income (loss) before income taxes	17,979			10,906			95,566			(202,507		)
Income tax (benefit) provision
Current	—			(1,141		)	—			(1,141		)
Total income tax benefit	—			(1,141		)	—			(1,141		)
Net income (loss)	17,979			12,047			95,566			(201,366		)
Net income attributable to non-controlling interest in subsidiaries	(2,940		)	(116		)	(8,034		)	(209		)
Net income (loss) attributable to Matador Resources Company shareholders	$	15,039		$	11,931		$	87,532		$	(201,575	)
Earnings (loss) per common share
Basic	$	0.15		$	0.13		$	0.87		$	(2.24	)
Diluted	$	0.15		$	0.13		$	0.87		$	(2.24	)
Weighted average common shares outstanding
Basic	100,365			93,384			100,141			90,016
Diluted	100,504			93,724			100,580			90,016



														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		Additional paid-in capital			Accumulated deficit			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	527	5		(5		)	—			—	—			—			—			—
Common stock issued to Board members and advisors	72	1		(1		)	—			—	—			—			—			—
Stock-based compensation expense related to equity-based awards including amounts capitalized	—	—		14,669			—			—	—			14,669			—			14,669
Stock options exercised, net of options forfeited in net share settlements	448	5		89			—			—	—			94			—			94
Restricted stock forfeited	—	—		—			—			120	(1,589		)	(1,589		)	—			(1,589		)
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	—	—		—			—			—	—			—			29,400			29,400
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	—	—		—			—			—	—			—			(5,635		)	(5,635		)
Current period net income	—	—		—			87,532			—	—			87,532			8,034			95,566
Balance at September 30, 2017	100,566	$	1,006	$	1,455,605		$	(548,819	)	126	$	(1,589	)	$	906,203		$	86,594		$	992,797



	Nine Months Ended September 30,
	2017			2016
Operating activities
Net income (loss)	$	95,566		$	(201,366	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives	(21,449		)	30,261
Depletion, depreciation and amortization	123,066			90,185
Accretion of asset retirement obligations	937			828
Full-cost ceiling impairment	—			158,633
Stock-based compensation expense	12,488			9,138
Amortization of debt issuance cost	103			899
Net gain on asset sales and inventory impairment	(23		)	(3,140		)
Changes in operating assets and liabilities
Accounts receivable	(50,343		)	(7,782		)
Lease and well equipment inventory	(1,666		)	(669		)
Prepaid expenses	(2,224		)	(74		)
Other assets	217			480
Accounts payable, accrued liabilities and other current liabilities	35,068			9,710
Royalties payable	29,651			5,225
Advances from joint interest owners	2,646			3,147
Income taxes payable	—			(2,848		)
Other long-term liabilities	(1,521		)	3,835
Net cash provided by operating activities	222,516			96,462
Investing activities
Oil and natural gas properties capital expenditures	(517,270		)	(288,175		)
Expenditures for other property and equipment	(80,560		)	(57,148		)
Proceeds from sale of assets	977			5,173
Restricted cash	—			43,098
Restricted cash in less-than-wholly-owned subsidiaries	(9,486		)	(544		)
Net cash used in investing activities	(606,339		)	(297,596		)
Financing activities
Borrowings under Credit Agreement	—			65,000
Proceeds from issuance of common stock	—			142,350
Cost to issue equity	—			(830		)
Proceeds from stock options exercised	2,920			—
Contributions related to formation of Joint Venture	171,500			—
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	29,400			—
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(5,635		)	—
Taxes paid related to net share settlement of stock-based compensation	(4,415		)	(1,552		)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	(2,653		)	—
Net cash provided by financing activities	191,117			204,968
(Decrease) increase in cash	(192,706		)	3,834
Cash at beginning of period	212,884			16,732
Cash at end of period	$	20,178		$	20,566

Supplemental disclosures of cash flow information (Note 12)

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.

The interim unaudited condensed consolidated financial statements of the Company 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 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 September 30, 2017. Amounts as of December 31, 2016 are derived from the Company’s audited consolidated financial statements included 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.

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 nine months ended September 30, 2017, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, no impairment charge was necessary. For the three months ended September 30, 2016, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, 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 nine months ended September 30, 2016, and as a result, the Company recorded impairment charges to its net capitalized costs of $158.6 million in its interim unaudited condensed consolidated statement of operations.

The Company capitalized approximately $6.1 million and $4.3 million of its general and administrative costs for the three months ended September 30, 2017 and 2016, respectively, and approximately $2.1 million and $0.7 million of its interest expense for the three months ended September 30, 2017 and 2016, respectively. The Company capitalized approximately $16.9 million and $10.3 million of its general and administrative costs for the nine months ended September 30, 2017 and 2016, respectively, and approximately $5.2 million and $2.9 million of its interest expense for the nine months ended September 30, 2017 and 2016, respectively.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Weighted average common shares outstanding
Basic	100,365	93,384	100,141	90,016
Dilutive effect of options and restricted stock units	139	340	439	—
Diluted weighted average common shares outstanding	100,504	93,724	100,580	90,016

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 the nine months ended September 30, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the nine months ended September 30, 2016, as the security holders do not have the obligation to share in the losses of the Company.

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 has reviewed the new guidance, including (i) identification of revenue streams and (ii) review of contracts and procedures currently in place, and is finalizing its evaluation of the impact, if any, on its consolidated financial statements.

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.

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 11).

On October 10, 2017, the Company completed a public offering of 8.0 million shares of its common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were and are being used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities, including the acceleration of the drilling of commercial salt water disposal wells in the Rustler Breaks asset area on behalf of San Mateo. The remaining proceeds will be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund a portion of the Company’s current and future capital expenditures.

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




Beginning asset retirement obligations	$	20,640
Liabilities incurred during period	1,901
Liabilities settled during period	(349		)
Revisions in estimated cash flows	794
Accretion expense	937
Ending asset retirement obligations	23,923
Less: current asset retirement obligations⁽¹⁾	(618		)
Long-term asset retirement obligations	$	23,305

_______________

At September 30, 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. At November 6, 2017, the Company had $575.0 million of outstanding 6.875% senior notes due 2023, no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the 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. Early in the fourth quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum facility amount remained at $500.0 million. This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million. Borrowings under the Credit Agreement are limited to the lowest 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 September 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.

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 of the issuer (Matador), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a 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 September 30, 2017
	Matador		Non-Guarantor Subsidiaries		Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	392,082	$	—	$	2,028	$	(394,110	)	$	—
Third-party current assets	635		11,676		138,034		—			150,345
Net property and equipment	—		185,464		1,511,703		—			1,697,167
Investment in subsidiaries	1,107,280		—		90,993		(1,198,273		)	—
Third-party long-term assets	—		—		1,025		—			1,025
Total assets	$	1,499,997	$	197,140	$	1,743,783	$	(1,592,383	)	$	1,848,537
LIABILITIES AND EQUITY
Intercompany payable	$	1,314	$	714	$	392,082	$	(394,110	)	$	—
Third-party current liabilities	18,453		18,191		215,451		—			252,095
Senior unsecured notes payable	574,027		—		—		—			574,027
Other third-party long-term liabilities	—		648		28,970		—			29,618
Total equity attributable to Matador Resources Company	906,203		90,993		1,107,280		(1,198,273		)	906,203
Non-controlling interest in subsidiaries	—		86,594		—		—			86,594
Total liabilities and equity	$	1,499,997	$	197,140	$	1,743,783	$	(1,592,383	)	$	1,848,537



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 September 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	11,242		$	122,675		$	(7,638	)	$	126,279
Total expenses	1,175			5,253			100,940			(7,638		)	99,730
Operating (loss) income	(1,175		)	5,989			21,735			—			26,549
Net gain on asset sales and inventory impairment	—			—			16			—			16
Interest expense	(8,550		)	—			—			—			(8,550		)
Other income	27			11			(74		)	—			(36		)
Earnings in subsidiaries	24,674			—			2,997			(27,671		)	—
Income before income taxes	14,976			6,000			24,674			(27,671		)	17,979
Total income tax (benefit) provision	(63		)	63			—			—			—
Net income attributable to non-controlling interest in subsidiaries	—			(2,940		)	—			—			(2,940		)
Net income attributable to Matador Resources Company shareholders	$	15,039		$	2,997		$	24,674		$	(27,671	)	$	15,039



Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	4,993		$	86,965		$	(3,225	)	$	88,733
Total expenses	1,018			2,043			72,043			(3,225		)	71,879
Operating (loss) income	(1,018		)	2,950			14,922			—			16,854
Net gain on asset sales and inventory impairment	—			—			1,073			—			1,073
Interest expense	(6,880		)	—			—			—			(6,880		)
Other expense	—			—			(141		)	—			(141		)
Income earnings in subsidiaries	19,800			—			2,805			(22,605		)	—
Income before income taxes	11,902			2,950			18,659			(22,605		)	10,906
Total income tax (benefit) provision	(29		)	29			(1,141		)	—			(1,141		)
Net income attributable to non-controlling interest in subsidiaries	—			(116		)	—			—			(116		)
Net income attributable to Matador Resources Company shareholders	$	11,931		$	2,805		$	19,800		$	(22,605	)	$	11,931



Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries		Eliminating Entries			Consolidated
Total revenues	$	—		$	32,179		$	382,520	$	(23,996	)	$	390,703
Total expenses	4,021			13,935			276,927		(23,996		)	270,887
Operating (loss) income	(4,021		)	18,244			105,593		—			119,816
Net gain on asset sales and inventory impairment	—			—			23		—			23
Interest expense	(26,229		)	—			—		—			(26,229		)
Other income	27			37			1,892		—			1,956
Earnings in subsidiaries	117,574			—			10,066		(127,640		)	—
Income before income taxes	87,351			18,281			117,574		(127,640		)	95,566
Total income tax (benefit) provision	(181		)	181			—		—			—
Net income attributable to non-controlling interest in subsidiaries	—			(8,034		)	—		—			(8,034		)
Net income attributable to Matador Resources Company shareholders	$	87,532		$	10,066		$	117,574	$	(127,640	)	$	87,532



Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	9,520		$	175,789		$	(5,860	)	$	179,449
Total expenses	3,985			4,420			362,290			(5,860		)	364,835
Operating (loss) income	(3,985		)	5,100			(186,501		)	—			(185,386		)
Net gain on asset sales and inventory impairment	—			—			3,140			—			3,140
Interest expense	(20,244		)	—			—			—			(20,244		)
Other expense	—			—			(17		)	—			(17		)
(Loss) earnings in subsidiaries	(177,400		)	—			4,837			172,563			—
(Loss) income before income taxes	(201,629		)	5,100			(178,541		)	172,563			(202,507		)
Total income tax (benefit) provision	(54		)	54			(1,141		)	—			(1,141		)
Net income attributable to non-controlling interest in subsidiaries	—			(209		)	—			—			(209		)
Net (loss) income attributable to Matador Resources Company shareholders	$	(201,575	)	$	4,837		$	(177,400	)	$	172,563		$	(201,575	)



Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2017
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(99,546	)	$	24,075		$	297,987		$	—		$	222,516
Net cash provided by (used in) investing activities	33			(85,114		)	(387,378		)	(133,880		)	(606,339		)
Net cash provided by (used in) financing activities	—			58,732			(1,495		)	133,880			191,117
(Decrease) increase in cash	(99,513		)	(2,307		)	(90,886		)	—			(192,706		)
Cash at beginning of period	99,795			2,307			110,782			—			212,884
Cash at end of period	$	282		$	—		$	19,896		$	—		$	20,178



Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2016
	Matador			Non-Guarantor Subsidiaries			Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(28,752	)	$	(2,726	)	$	127,940		$	—		$	96,462
Net cash used in investing activities	(112,720		)	(51,904		)	(300,201		)	167,229			(297,596		)
Net cash provided by financing activities	141,520			54,510			176,167			(167,229		)	204,968
Increase (decrease) in cash	48			(120		)	3,906			—			3,834
Cash at beginning of period	80			186			16,466			—			16,732
Cash at end of period	$	128		$	66		$	20,372		$	—		$	20,566

The Company’s deferred tax assets exceeded its deferred tax liabilities at September 30, 2017 due to the deferred tax assets generated by the full-cost ceiling impairment charges recorded in prior periods. The Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at September 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.

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.



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	10/01/2017 - 12/31/2017	1,230,000	$	45.17	$	55.75	$	(1,452	)
Oil	01/01/2018 - 12/31/2018	2,880,000	$	44.27	$	60.29	670
Natural Gas	10/01/2017 - 12/31/2017	6,270,000	$	2.51	$	3.60	(129		)
Natural Gas	01/01/2018 - 12/31/2018	16,800,000	$	2.58	$	3.67	(249		)
Total open costless collar contracts							$	(1,160	)

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 September 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
September 30, 2017
Current assets	$	89,456		$	(89,396	)	$	60
Other assets	29,939			(29,654		)	285
Current liabilities	(93,037		)	89,396			(3,641		)
Other liabilities	(29,863		)	29,654			(209		)
Total	$	(3,505	)	$	—		$	(3,505	)
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 September 30,					Nine Months Ended September 30,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2017			2016		2017			2016
Derivative Instrument
Oil	Revenues: Realized gain (loss) on derivatives	$	485		$	837	$	(568	)	$	6,861
Natural Gas	Revenues: Realized gain (loss) on derivatives	—			48		(608		)	3,552
Realized gain (loss) on derivatives		485			885		(1,176		)	10,413
Oil	Revenues: Unrealized (loss) gain on derivatives	(12,479		)	2,007		15,949			(24,967		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	115			1,196		5,508			(5,294		)
NGL	Revenues: Unrealized loss on derivatives	(8		)	—		(8		)	—
Unrealized (loss) gain on derivatives		(12,372		)	3,203		21,449			(30,261		)
Total		$	(11,887	)	$	4,088	$	20,273		$	(19,848	)

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 included firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas was purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contained fixed processing and liquids transportation and fractionation fees, and the revenue the Company received varied with the quality of natural gas transported to the processing facilities and the contract period.

Under this agreement, if the Company did not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it would 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 could 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 $0.4 million and $0.7 million in processing and transportation fees under this agreement during the three months ended September 30, 2017 and 2016, respectively, and $1.4 million and $2.4 million in processing and transportation fees under this agreement during the nine months ended September 30, 2017 and 2016, respectively.

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 September 30, 2017, the total deficiency fee required to be paid would be approximately $11.4 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 $4.0 million and $2.4 million in natural gas processing and gathering fees under this agreement during the three months ended September 30, 2017 and 2016, respectively, and $10.8 million and $7.1 million in natural gas processing and gathering fees under this agreement during the nine months ended September 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.

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 provides 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 September 30, 2017 was approximately $245.6 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 $57.0 million. The subsidiary of San Mateo paid approximately $22.4 million and $32.3 million under these agreements during the three and nine months ended September 30, 2017, respectively. As of September 30, 2017, the remaining obligations under these agreements were $24.7 million, which are expected to be incurred within the next year.

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. 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 $36.1 million at September 30, 2017.

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



	September 30, 2017		December 31, 2016
Accrued evaluated and unproved and unevaluated property costs	$	90,789	$	54,273
Accrued support equipment and facilities costs	15,401		15,139
Accrued lease operating expenses	14,217		16,009
Accrued interest on debt	18,228		6,541
Accrued asset retirement obligations	618		915
Accrued partners’ share of joint interest charges	18,018		5,572
Other	1,074		3,011
Total accrued liabilities	$	158,345	$	101,460

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



	Nine Months Ended September 30,
	2017			2016
Cash paid for interest expense, net of amounts capitalized	$	14,542		$	13,370
Increase in asset retirement obligations related to mineral properties	$	2,484		$	2,588
(Decrease) increase in asset retirement obligations related to support equipment and facilities	$	(138	)	$	644
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	$	35,940		$	(7,849	)
Decrease in liabilities for support equipment and facilities	$	(247	)	$	(2,687	)
Stock-based compensation expense recognized as liability	$	150		$	457
Decrease in liabilities for accrued cost to issue equity	$	(343	)	$	—
Transfer of inventory from oil and natural gas properties	$	74		$	655

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
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended September 30, 2017
Oil and natural gas revenues	$	134,488		$	460	$	—		$	—		$	134,948
Midstream services revenues	—			11,261		—			(8,043		)	3,218
Realized gain on derivatives	485			—		—			—			485
Unrealized loss on derivatives	(12,372		)	—		—			—			(12,372		)
Expenses⁽¹⁾	86,728			5,598		15,447			(8,043		)	99,730
Operating income (loss)⁽²⁾	$	35,873		$	6,123	$	(15,447	)	$	—		$	26,549
Total assets	$	1,590,677		$	222,274	$	35,586		$	—		$	1,848,537
Capital expenditures⁽³⁾	$	180,686		$	35,008	$	1,494		$	—		$	217,188



	Exploration and Production							Consolidations and Eliminations			Consolidated Company
	Exploration and Production		Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended September 30, 2016
Oil and natural gas revenues	$	82,794	$	285	$	—		$	—		$	83,079
Midstream services revenues	—		5,609		—			(4,043		)	1,566
Realized gain on derivatives	885		—		—			—			885
Unrealized gain on derivatives	3,203		—		—			—			3,203
Expenses⁽¹⁾	60,222		2,277		13,423			(4,043		)	71,879
Operating income (loss)⁽²⁾	$	26,660	$	3,617	$	(13,423	)	$	—		$	16,854
Total assets	$	1,020,648	$	124,153	$	32,892		$	—		$	1,177,693
Capital expenditures	$	116,279	$	17,370	$	1,903		$	—		$	135,552

_____________________



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Nine Months Ended September 30, 2017
Oil and natural gas revenues	$	362,040		$	1,519	$	—		$	—		$	363,559
Midstream services revenues	—			32,244		—			(25,373		)	6,871
Realized loss on derivatives	(1,176		)	—		—			—			(1,176		)
Unrealized gain on derivatives	21,449			—		—			—			21,449
Expenses⁽¹⁾	233,145			16,060		47,055			(25,373		)	270,887
Operating income (loss)⁽²⁾	$	149,168		$	17,703	$	(47,055	)	$	—		$	119,816
Total assets	$	1,590,677		$	222,274	$	35,586		$	—		$	1,848,537
Capital expenditures⁽³⁾	$	554,642		$	75,235	$	4,710		$	—		$	634,587



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Nine Months Ended September 30, 2016
Oil and natural gas revenues	$	195,467		$	874	$	—		$	—		$	196,341
Midstream services revenues	—			11,168		—			(8,212		)	2,956
Realized gain on derivatives	10,413			—		—			—			10,413
Unrealized loss on derivatives	(30,261		)	—		—			—			(30,261		)
Expenses⁽¹⁾	327,585			5,373		40,089			(8,212		)	364,835
Operating (loss) income⁽²⁾	$	(151,966	)	$	6,669	$	(40,089	)	$	—		$	(185,386	)
Total assets	$	1,020,648		$	124,153	$	32,892		$	—		$	1,177,693
Capital expenditures	$	278,396		$	49,620	$	5,485		$	—		$	333,501

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our 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.

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:

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.

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.

For the three months ended September 30, 2017, our total oil equivalent production was 3.9 million BOE, and our average daily oil equivalent production was 41,954 BOE per day, of which 23,538 Bbl per day, or 56%, was oil and 110.5 MMcf per day, or 44%, was natural gas. Our oil production of 2.2 million Bbl for the three months ended September 30, 2017 increased 57% year-over-year from 1.4 million Bbl for the three months ended September 30, 2016. Our natural gas production of 10.2 Bcf for the three months ended September 30, 2017 increased 28% year-over-year from 8.0 Bcf for the three months ended September 30, 2016. For the nine months ended September 30, 2017, our total oil equivalent production was 10.2 million BOE, and our average daily oil equivalent production was 37,325 BOE per day, of which 20,447 Bbl per day, or 55%, was oil and 101.3 MMcf per day, or 45%, was natural gas. Our oil production of 5.6 million Bbl for the nine months ended September 30, 2017 increased 53% year-over-year from 3.7 million Bbl for the nine months ended September 30, 2016. Our natural gas production of 27.6 Bcf for the nine months ended September 30, 2017 increased 22% year-over-year from 22.6 Bcf for the nine months ended September 30, 2016.

For the third quarter of 2017, we reported net income attributable to Matador Resources Company shareholders of approximately $15.0 million, or $0.15 per diluted common share on a GAAP basis, as compared to net income attributable to Matador Resources Company shareholders of $11.9 million, or $0.13 per diluted common share, for the third quarter of 2016. For the third quarter of 2017, our Adjusted EBITDA attributable to Matador Resources Company shareholders (“Adjusted EBITDA”), a non-GAAP financial measure, was $84.8 million, as compared to Adjusted EBITDA of $47.3 million during the third quarter of 2016. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss)

For the nine months ended September 30, 2017, we reported net income attributable to Matador Resources Company shareholders of approximately $87.5 million, or $0.87 per diluted common share, on a GAAP basis, as compared to a net loss attributable to Matador Resources Company shareholders of $201.6 million, or $2.24 per diluted common share, for the nine months ended September 30, 2016. For the nine months ended September 30, 2017, our Adjusted EBITDA, a non-GAAP financial measure, was $227.4 million, as compared to Adjusted EBITDA of $103.4 million during the nine months ended September 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 third quarter of 2017, see “— Results of Operations” below.

During the third 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. During the third quarter of 2017, we took delivery of a sixth drilling rig for the purpose of drilling a second commercial salt water disposal well in the Rustler Breaks asset area for San Mateo. The salt water disposal well was not ready to spud until early August 2017, and, in the interim, we used this rig to drill one additional oil and natural gas well in our Rustler Breaks asset area. Subsequent to drilling this second salt water disposal well, San Mateo elected to commission the drilling and completion of three additional commercial salt water disposal wells and the construction of associated commercial salt water disposal facilities in the Rustler Breaks asset area, resulting in five commercial salt water disposal wells in the Rustler Breaks asset area by mid-2018.

We finished drilling our five-well program in the Eagle Ford shale in South Texas in the second quarter of 2017. Two of these wells were completed and turned to sales in the second quarter of 2017. The other three gross (3.0 net) wells were completed and turned to sales in early July 2017. 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 26 gross (17.9 net) wells in the Delaware Basin during the third quarter of 2017, including 19 gross (16.0 net) operated and seven gross (1.9 net) non-operated horizontal wells. In the Rustler Breaks and Antelope Ridge asset areas, we began producing oil and natural gas from a total of 19 gross (12.6 net) wells during the third quarter of 2017, including 13 gross (10.8 net) operated and six gross (1.8 net) non-operated wells. Of the 13 gross operated wells in the Rustler Breaks asset area, ten were Wolfcamp A-XY completions, two were Wolfcamp B-Blair completions and one was a Second Bone Spring completion. In addition, we began producing oil and natural gas from two gross (2.0 net) operated wells in the Wolf asset area during the third quarter of 2017, including our first operated completions in the Wolf asset area in the Wolfcamp B and Avalon formations. In the Ranger and Arrowhead asset areas, we began producing oil and natural gas from five gross (3.3 net) wells, including four gross (3.2 net) operated wells and one gross (0.1 net) non-operated well during the third quarter of 2017.

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 third quarter of 2017 was 30,707 BOE per day, consisting of 18,689 Bbl of oil per day and 72.1 MMcf of natural gas per day, a 66% increase from production of 18,498 BOE per day, consisting of 11,751 Bbl of oil per day and 40.5 MMcf of natural gas per day, in the third quarter of 2016. The Delaware Basin contributed approximately 79% of our daily oil production and approximately 65% of our daily natural gas production in the third quarter of 2017, as compared to approximately 79% of our daily oil production and approximately 47% of our daily natural gas production in the third quarter of 2016.

During the third quarter of 2017 and through November 6, 2017, we acquired approximately 9,700 net acres in the Delaware Basin, mostly in and around our existing acreage positions, including new leasing activities and acquisitions of small interests from mineral and working interest owners in our operated wells. From January 1 through November 6, 2017, we acquired approximately 25,000 net acres in the Delaware Basin, including a small volume of associated production, for a total acquisition cost of approximately $224 million. At November 6, 2017, we held approximately 201,100 gross (115,700 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 as strategic opportunities are identified.

On October 10, 2017, we completed a public offering of 8.0 million shares of our common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were and are being used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities, including the acceleration of the drilling of commercial salt water disposal wells in the Rustler Breaks asset area on behalf of San Mateo. The remaining proceeds will

As of November 6, 2017, we adjusted our anticipated capital expenditures for drilling and completions (including equipping wells for production) from $400 to $420 million to $440 to $465 million, and we adjusted our anticipated midstream capital expenditures from $56 to $64 million to $66 to $74 million. The updated midstream capital expenditures primarily represent our 51% share of the updated 2017 capital expenditure budget of $125 to $140 million for San Mateo. We 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 operated 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.

The following table sets forth our estimated total proved oil and natural gas reserves at September 30, 2017, December 31, 2016 and September 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. The reserves estimates were based on evaluations prepared by our engineering staff in accordance with the SEC’s rules for oil and natural gas reserves reporting and do not include any unproved reserves classified as probable or possible that might exist on our properties. In addition, the reserves estimates at December 31, 2016 and September 30, 2016 were audited by an independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.



	September 30, 2017			December 31, 2016			September 30, 2016
Estimated Proved Reserves Data: ⁽¹⁾⁽²⁾
Estimated proved reserves:
Oil (MBbl)⁽³⁾	83,014			56,977			55,031
Natural Gas (Bcf)⁽⁴⁾	377.1			292.6			279.4
Total (MBOE)⁽⁵⁾	145,860			105,752			101,604
Estimated proved developed reserves:
Oil (MBbl)⁽³⁾	31,961			22,604			21,204
Natural Gas (Bcf)⁽⁴⁾	164.4			126.8			118.8
Total (MBOE)⁽⁵⁾	59,357			43,731			41,012
Percent developed	40.7		%	41.4		%	40.4		%
Estimated proved undeveloped reserves:
Oil (MBbl)⁽³⁾	51,053			34,373			33,827
Natural Gas (Bcf)⁽⁴⁾	212.7			165.9			160.6
Total (MBOE)⁽⁵⁾	86,503			62,021			60,592
Standardized Measure⁽⁶⁾ (in millions)	$	1,096.2		$	575.0		$	516.8
PV-10⁽⁷⁾ (in millions)	$	1,225.9		$	581.5		$	524.7

At September 30, 2017, our estimated total proved oil and natural gas reserves were 145.9 million BOE, including 83.0 million Bbl of oil and 377.1 Bcf of natural gas, with a Standardized Measure of $1,096.2 million and a PV-10, a non-GAAP financial measure, of $1,225.9 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 September 30, 2016, our estimated total proved oil and natural gas reserves were 101.6 million BOE, including 55.0 million Bbl of oil and 279.4 Bcf of natural gas. Our proved oil reserves of 83.0 million Bbl at September 30, 2017 increased 46%, as compared to 57.0 million Bbl at December 31, 2016, and increased 51%, as compared to 55.0 million Bbl at September 30, 2016. At September 30, 2017, approximately 41% of our total proved reserves were proved developed reserves, 57% of our total proved reserves were oil and 43% 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 66% from 74.0 million BOE at September 30, 2016, or 73% of our total proved oil and natural gas reserves, including 44.1 million Bbl of oil and 179.3 Bcf of natural gas, to 122.7 million BOE, or 84% of our total proved oil and natural gas reserves, including 74.4 million Bbl of oil and 289.7 Bcf of natural gas, at September 30, 2017.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017			2016
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	100,150		$	58,589	$	265,107		$	141,437
Natural gas	34,798			24,490		98,452			54,904
Total oil and natural gas revenues	134,948			83,079		363,559			196,341
Third-party midstream services revenues	3,218			1,566		6,871			2,956
Realized gain (loss) on derivatives	485			885		(1,176		)	10,413
Unrealized (loss) gain on derivatives	(12,372		)	3,203		21,449			(30,261		)
Total revenues	$	126,279		$	88,733	$	390,703		$	179,449
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	2,166			1,376		5,582			3,650
Natural gas (Bcf)⁽³⁾	10.2			8.0		27.6			22.6
Total oil equivalent (MBOE)⁽⁴⁾	3,860			2,703		10,190			7,423
Average daily production (BOE/d)⁽⁵⁾	41,954			29,381		37,325			27,091
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	46.25		$	42.57	$	47.49		$	38.75
Oil, with realized derivatives (per Bbl)	$	46.47		$	43.18	$	47.39		$	40.63
Natural gas, without realized derivatives (per Mcf)	$	3.42		$	3.08	$	3.56		$	2.43
Natural gas, with realized derivatives (per Mcf)	$	3.42		$	3.08	$	3.54		$	2.58

Oil and natural gas revenues. Our oil and natural gas revenues increased $51.9 million to $134.9 million, or 62%, for the three months ended September 30, 2017, as compared to $83.1 million for the three months ended September 30, 2016. Our oil revenues increased $41.6 million, or 71%, to $100.2 million for the three months ended September 30, 2017, as compared to $58.6 million for the three months ended September 30, 2016. The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the three months ended September 30, 2017 of $46.25 per Bbl, as compared to $42.57 per Bbl realized for the three months ended September 30, 2016, and (ii) the 57% increase in oil production to 2.2 million Bbl of oil for the three months ended September 30, 2017, or about 23,538 Bbl of oil per day, as compared to 1.4 million Bbl of oil, or about 14,960 Bbl of oil per day, for the three months ended September 30, 2016. The increase in oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, but also to production from the five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Our natural gas revenues increased by $10.3 million, or 42%, to $34.8 million for the three months ended September 30, 2017, as compared to $24.5 million for the three months ended September 30, 2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the three months ended September 30, 2017 of $3.42 per Mcf, as compared to $3.08 per Mcf realized for the three months ended September 30, 2016, and (ii) the 28% increase in our natural gas production to 10.2 Bcf for the three months ended September 30, 2017, as compared to 8.0 Bcf for the three months ended September 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 $1.7 million to $3.2 million, or 105%, for the three months ended September 30, 2017, as compared to $1.6 million for the three months ended September 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 three months ended September 30, 2017, as compared to $1.0 million for the three months ended September 30, 2016, due to (i) our natural gas gathering system and the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”) being placed into service in the second half of 2016 and (ii) increased natural gas production in our Rustler Breaks and Wolf asset areas.

Realized gain on derivatives. Our realized net gain on derivatives was $0.5 million for the three months ended September 30, 2017, as compared to a realized net gain of $0.9 million for the three months ended September 30, 2016. We realized a net gain of $0.5 million from our oil derivative contracts for the three months ended September 30, 2017 resulting from oil prices below the floor prices of certain of our oil costless collar contracts. We realized a net gain of $0.8 million from our oil derivative contracts for the three months ended September 30, 2016 resulting from oil prices that were below the floor prices of the majority of our oil costless collar contracts. We realized an average gain of approximately $0.39 per Bbl hedged on all of our open oil costless collar contracts during the three months ended September 30, 2017, as compared to an average gain of $1.21 per Bbl hedged on all of our open oil costless collar contracts for the three months ended September 30, 2016. Our oil volumes hedged for the three months ended September 30, 2017 were 78% higher as compared to the three months ended September 30, 2016. We did not realize a gain or loss per MMBtu hedged on any of our open natural gas collar contracts during the three months ended September 30, 2017, as compared to an average gain of approximately $0.02 per MMBtu hedged on all of our open natural gas costless collar contracts for the three months ended September 30, 2016. Our total natural gas volumes hedged for the three months ended September 30, 2017 were 109% higher than the total natural gas volumes hedged for the three months ended September 30, 2016.

Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives was $12.4 million for the three months ended September 30, 2017, as compared to an unrealized net gain of $3.2 million for the three months ended September 30, 2016. During the three months ended September 30, 2017, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to a liability of approximately $3.5 million from an asset of $8.9 million at June 30, 2017, resulting in an unrealized net loss on derivatives of $12.4 million for the three months ended September 30, 2017. During the three months ended September 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts increased to a liability of $14.0 million from a liability of $17.2 million at June 30, 2016, resulting in an unrealized gain on derivatives of $3.2 million for the three months ended September 30, 2016.

Oil and natural gas revenues. Our oil and natural gas revenues increased $167.2 million to $363.6 million, or 85%, for the nine months ended September 30, 2017, as compared to $196.3 million for the nine months ended September 30, 2016. Our oil revenues increased $123.7 million, or 87%, to $265.1 million for the nine months ended September 30, 2017, as compared to $141.4 million for the nine months ended September 30, 2016. The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the nine months ended September 30, 2017 of $47.49 per Bbl, as compared to $38.75 per Bbl realized for the nine months ended September 30, 2016, and (ii) the 53% increase in oil production to 5.6 million Bbl of oil in the nine months ended September 30, 2017, or about 20,447 Bbl of oil per day, as compared to 3.7 million Bbl of oil, or about 13,322 Bbl of oil per day, in the nine months ended September 30, 2016. This increased oil production is primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, but also to production from the five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Our natural gas revenues increased by $43.5 million, or 79%, to $98.5 million for the nine months ended September 30, 2017, as compared to $54.9 million for the nine months ended September 30, 2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the nine months ended September 30, 2017 of $3.56 per Mcf, as compared to $2.43 per Mcf realized for the nine months ended September 30, 2016, and (ii) the 22% increase in our natural gas production to 27.6 Bcf for the nine months ended September 30, 2017, as compared to 22.6 Bcf for the nine months ended September 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 $3.9 million to $6.9 million, or 132%, for the nine months ended September 30, 2017, as compared to $3.0 million for the nine months ended September 30, 2016. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately $5.6 million for the nine months ended September 30, 2017, as compared to $1.6 million for the nine months ended September 30, 2016, due to (i) our natural gas gathering system and the Black River Processing Plant being placed into service in the second half of 2016 and (ii) increased natural gas production in our Rustler Breaks and Wolf asset areas.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $1.2 million for the nine months ended September 30, 2017, as compared to a net gain of approximately $10.4 million for the nine months ended September 30, 2016. We realized net losses of $0.6 million from both our oil and natural gas derivative contracts, respectively, for the nine months ended September 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 $6.9 million and $3.6 million from our oil and natural gas derivative contracts, respectively, for the nine months ended September 30, 2016, resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. We realized an average loss of approximately $0.17 per Bbl hedged on all of our open oil costless collar contracts during the nine months ended September 30, 2017, as compared to an average gain of $3.67 per Bbl hedged on all of our open oil costless collar contracts for the nine months ended September 30, 2016. Our oil volumes hedged for the nine months ended September 30, 2017 were 83% higher as compared to the nine months ended September 30, 2016. We realized an average loss of approximately $0.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the nine months ended September 30, 2017, as compared to an average gain of approximately $0.41 per MMBtu hedged on all of our open natural gas costless collar contracts for the nine months ended September 30, 2016. Our total natural gas volumes hedged for the nine months ended September 30, 2017 were 104% higher than the total natural gas volumes hedged for the nine months ended September 30, 2016.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $21.4 million for the nine months ended September 30, 2017, as compared to an unrealized loss of approximately $30.3 million for the nine months ended September 30, 2016. During the period from December 31, 2016 through September 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 a liability of approximately $3.5 million, resulting in an unrealized gain on derivatives of approximately $21.4 million for the nine months ended September 30, 2017. This increase is primarily attributable to the decrease in oil and natural gas futures prices during the nine months ended September 30, 2017. During the period from December 31, 2015 through September 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 $14.0 million, resulting in an unrealized loss on derivatives of approximately $30.3 million for the nine months ended September 30, 2016.



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands, except expenses per BOE)	2017			2016			2017			2016
Expenses:
Production taxes, transportation and processing	$	15,666		$	12,388		$	40,348		$	30,846
Lease operating	16,689			14,605			48,486			41,300
Plant and other midstream services operating	3,096			1,449			8,379			3,537
Depletion, depreciation and amortization	47,800			30,015			123,066			90,185
Accretion of asset retirement obligations	323			276			937			828
Full-cost ceiling impairment	—			—			—			158,633
General and administrative	16,156			13,146			49,671			39,506
Total expenses	$	99,730		$	71,879		$	270,887		$	364,835
Operating income (loss)	$	26,549		$	16,854		$	119,816		$	(185,386	)
Other income (expense):
Net gain on asset sales and inventory impairment	$	16		$	1,073		$	23		$	3,140
Interest expense	(8,550		)	(6,880		)	(26,229		)	(20,244		)
Other (expense) income	(36		)	(141		)	1,956			(17		)
Total other expense	$	(8,570	)	$	(5,948	)	$	(24,250	)	$	(17,121	)
Income (loss) before income taxes	$	17,979		$	10,906		$	95,566		$	(202,507	)
Total income tax benefit	—			(1,141		)	—			(1,141		)
Net income attributable to non-controlling interest in subsidiaries	(2,940		)	(116		)	(8,034		)	(209		)
Net income (loss) attributable to Matador Resources Company shareholders	$	15,039		$	11,931		$	87,532		$	(201,575	)
Expenses per BOE:
Production taxes, transportation and processing	$	4.06		$	4.58		$	3.96		$	4.16
Lease operating	$	4.32		$	5.40		$	4.76		$	5.56
Plant and other midstream services operating	$	0.80		$	0.54		$	0.82		$	0.48
Depletion, depreciation and amortization	$	12.38		$	11.10		$	12.08		$	12.15
General and administrative	$	4.19		$	4.86		$	4.87		$	5.32

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased by $3.3 million to $15.7 million, or 26%, for the three months ended September 30, 2017, as compared to $12.4 million for the three months ended September 30, 2016. The increase in production taxes, transportation and processing expenses was primarily attributable to the increase in our production taxes of $3.4 million to $8.1 million for the three months ended September 30, 2017, as compared to $4.6 million for the three months ended September 30, 2016, primarily due to the 62% increase in oil and natural gas revenues for the three months ended September 30, 2017, as compared to the three months ended September 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. We realized a decrease in transportation and processing expenses year-over-year primarily as a result of the start-up in late August 2016 of the Black River Processing Plant. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 11% to $4.06 per BOE for the three months ended September 30, 2017, as compared to $4.58 per BOE for the three months ended September 30, 2016. On a unit-of-production basis, these third quarter 2017 expenses benefited from significantly higher total oil equivalent production, which increased 43% in the third quarter of 2017, as compared to the third quarter of 2016.

Lease operating. Our lease operating expenses increased by $2.1 million to $16.7 million, or an increase of 14%, for the three months ended September 30, 2017, as compared to $14.6 million for the three months ended September 30, 2016. The increase in lease operating expenses on an absolute basis for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016, was primarily attributable to an increase in costs of services and equipment related to the

increased number of wells at September 30, 2017, as compared to September 30, 2016, as a result of our increased delineation and development drilling activities in the Delaware Basin. On a unit-of-production basis, these third quarter 2017 expenses benefited from significantly higher total oil equivalent production, which increased 43% to approximately 3.9 million BOE for the three months ended September 30, 2017 from approximately 2.7 million BOE for the three months ended September 30, 2016. These third quarter 2017 expenses also benefited from lower contract labor and workover expenses, as well as continued improvement in other areas, including operational efficiencies. Our lease operating expenses on a unit-of-production basis decreased 20% to $4.32 per BOE for the three months ended September 30, 2017, as compared to $5.40 per BOE for the three months ended September 30, 2016.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased by $1.6 million to $3.1 million, an increase of 114%, for the three months ended September 30, 2017, as compared to $1.4 million for the three months ended September 30, 2016. This increase was partially attributable to the expenses associated with our commercial salt water disposal operations of $1.6 million for the three months ended September 30, 2017, as compared to $1.0 million for the three months ended September 30, 2016, as a result of additional commercial salt water disposal wells operating in the three months ended September 30, 2017. Most of the remaining increase was attributable to expenses of $1.0 million for the three months ended September 30, 2017, as compared to $0.3 million for the three months ended September 30, 2016, 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 $17.8 million to $47.8 million, or an increase of 59%, for the three months ended September 30, 2017, as compared to $30.0 million for the three months ended September 30, 2016. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased to $12.38 per BOE for the three months ended September 30, 2017, as compared to $11.10 per BOE for the three months ended September 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 43% increase in oil and natural gas production to 3.9 million BOE for the three months ended September 30, 2017, as compared to 2.7 million BOE for the three months ended September 30, 2016. The impact of the increase in well costs and oil and natural gas production on depletion, depreciation and amortization was partially offset by higher total proved reserves of 145.9 million BOE, or an increase of 44%, at September 30, 2017, as compared to total proved reserves of 101.6 million BOE at September 30, 2016. The increase in total proved oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. In addition, depreciation expenses attributable to our midstream segment were approximately $1.3 million for the three months ended September 30, 2017, as compared to $0.8 million for the three months ended September 30, 2016.

General and administrative. Our general and administrative expenses increased $3.0 million to $16.2 million, an increase of 23%, for the three months ended September 30, 2017, as compared to $13.1 million for the three months ended September 30, 2016. The increase in our general and administrative expenses was primarily attributable to increased payroll expenses of approximately $4.7 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 primarily offset by the increase in capitalized general and administrative expenses of $1.8 million due to our increased delineation and development drilling activities in the Delaware Basin for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. As a result of the 43% increase in oil and natural gas production for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016, our general and administrative expenses decreased 14% on a unit-of-production basis to $4.19 per BOE for the three months ended September 30, 2017, as compared to $4.86 per BOE for the three months ended September 30, 2016.

Interest expense. For the three months ended September 30, 2017, we incurred total interest expense of approximately $10.6 million. We capitalized approximately $2.1 million of our interest expense on certain qualifying projects for the three months ended September 30, 2017 and expensed the remaining $8.6 million to operations. For the three months ended September 30, 2016, we incurred total interest expense of approximately $7.6 million. We capitalized $0.7 million of our interest expense on certain qualifying projects for the three months ended September 30, 2016 and expensed the remaining $6.9 million to operations. The increase in total interest expense of $3.0 million for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016, was primarily attributable to an increase in our average debt outstanding. At September 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 September 30, 2016, we had $65.0 million borrowings outstanding and $0.8 million in letters of credit outstanding under our Credit Agreement and $400.0 million in outstanding senior notes.

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased by approximately $9.5 million to $40.3 million, or 31%, for the nine months ended September 30, 2017, as compared to $30.8 million for the nine months ended September 30, 2016. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased to $3.96 per BOE for the nine months ended September 30, 2017, as compared to $4.16 per BOE for the nine months ended September 30, 2016. The increase in production taxes, transportation and processing expenses on an absolute basis was primarily attributable to the $11.4 million increase in our production taxes to $22.2 million for the nine months ended September 30, 2017, as compared to $10.7 million for the nine months ended September 30, 2016, primarily due to the $167.2 million increase in oil and natural gas revenues for the nine months ended September 30, 2017, as compared to the nine months ended September 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 $18.2 million for the nine months ended September 30, 2017, as compared to transportation and processing expenses of $20.1 million for the nine months ended September 30, 2016. This decrease of $1.9 million was primarily due to (i) the start-up in late August 2016 of the Black River Processing Plant, which processes most of our natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and (ii) the 29% 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 nine months ended September 30, 2017 benefited from significantly higher total oil equivalent production, which increased 37% in the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016.

Lease operating. Our lease operating expenses increased by $7.2 million to $48.5 million, or 17%, for the nine months ended September 30, 2017, as compared to $41.3 million for the nine months ended September 30, 2016. The increase in lease operating expenses on an absolute basis for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016, was primarily attributable to an increase in costs of services and equipment related to the increased number of wells at September 30, 2017, as compared to September 30, 2016, as a result of our increased delineation and development drilling activities in the Delaware Basin. Our lease operating expenses on a unit-of-production basis decreased 14% to $4.76 per BOE for the nine months ended September 30, 2017, as compared to $5.56 per BOE for the nine months ended September 30, 2016. These expenses for the nine months ended September 30, 2017 also benefited from lower contract labor and workover expenses, as well as continued improvement in other areas, including operational efficiencies.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased by $4.8 million to $8.4 million, an increase of 137%, for the nine months ended September 30, 2017, as compared to $3.5 million for the nine months ended September 30, 2016. This increase was partially attributable to the expenses associated with our commercial salt water disposal operations of $4.7 million for the nine months ended September 30, 2017, as compared to $2.5 million for the nine months ended September 30, 2016, as a result of additional commercial salt water disposal wells operating during the nine months ended September 30, 2017. The remaining increase was attributable to expenses of $2.8 million for the nine months ended September 30, 2017, as compared to $0.3 million for the nine months ended September 30, 2016, 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 $32.9 million to $123.1 million, or 36%, for the nine months ended September 30, 2017, as compared to $90.2 million for the nine months ended September 30, 2016. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 1% to $12.08 per BOE for the nine months ended September 30, 2017, as compared to $12.15 per BOE for the nine months ended September 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 37% increase in oil and natural gas production to 10.2 million BOE for the nine months ended September 30, 2017, as compared to 7.4 million BOE for the nine months ended September 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 145.9 million BOE, or an increase of 44%, at September 30, 2017, as compared to total proved reserves of 101.6 million BOE at September 30, 2016. The increase in total proved oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. In addition, depreciation expenses attributable to our midstream segment were approximately $3.8 million for the nine months ended September 30, 2017, as compared to $1.7 million for the nine months ended September 30, 2016.

General and administrative. Our general and administrative expenses increased $10.2 million to $49.7 million, an increase of 26%, for the nine months ended September 30, 2017, as compared to $39.5 million for the nine months ended September 30, 2016. The increase in our general and administrative expenses was partially attributable to the $3.4 million increase in non-cash stock-based compensation expense to $12.5 million for the nine months ended September 30, 2017, as compared to $9.1 million for the nine months ended September 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 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 $11.0 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 $6.6 million due to our increased delineation and development drilling activities in the Delaware Basin for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. Our general and administrative expenses decreased 8% on a unit-of-production basis to $4.87 per BOE for the nine months ended September 30, 2017, as compared to $5.32 per BOE for the nine months ended September 30, 2016, primarily due to our increased total oil equivalent production.

Interest expense. For the nine months ended September 30, 2017, we incurred total interest expense of approximately $31.5 million. We capitalized approximately $5.2 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2017 and expensed the remaining $26.2 million to operations. For the nine months ended September 30, 2016, we incurred total interest expense of approximately $23.2 million. We capitalized $2.9 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2016 and expensed the remaining $20.2 million to operations. The increase in total interest expense of $8.3 million for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016, was primarily attributable to an increase in the average debt outstanding. At September 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 September 30, 2016, we had $65.0 million of borrowings outstanding and $0.8 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 September 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 September 30, 2017 due to uncertainties regarding the future realization of our deferred tax assets.

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 and into 2018 with a combination of cash on hand (including proceeds we received from our October 2017 equity offering), 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 Capital Partners, LLC (“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 provides 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 and into 2018. At the beginning of the fourth quarter of 2017, we were operating five drilling rigs that were drilling oil and natural gas wells in the Delaware Basin—one rig was drilling in our Wolf asset area in Loving County, Texas, three rigs were drilling in our Rustler Breaks asset area in Eddy County, New Mexico and one rig was drilling in our Ranger asset area in Lea County, New Mexico. As of November 6, 2017, we adjusted our anticipated capital expenditures for drilling and completions (including equipping wells for production) from $400 to $420 million to $440 to $465 million, and we adjusted our anticipated midstream capital expenditures from $56 to $64 million to $66 to $74 million. The updated midstream capital expenditures primarily represent our 51% share of the updated 2017 capital expenditure budget of $125 to $140 million for San Mateo. We 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 operated 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 third quarter of 2017 and through November 6, 2017, we acquired approximately 9,700 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. From January 1 through November 6, 2017, we acquired 25,000 net acres in the Delaware Basin, including a small volume of associated production, for a total acquisition cost of approximately $224 million. At November 6, 2017, we held approximately 201,100 gross (115,700 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.

At September 30, 2017, we had cash totaling approximately $20.2 million and restricted cash totaling approximately $10.7 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 of our cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. Additionally, at September 30, 2017, we had no outstanding borrowings under our Credit Agreement, which had a borrowing base of $450.0 million and an elected commitment of $400.0 million at such date. Early in the fourth quarter of 2017, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at June 30, 2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum facility amount remained at $500.0 million. This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. We elected to keep the borrowing commitment at $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment.

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 and into 2018 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 November 6, 2017, we had approximately 55% of our anticipated oil production and approximately 65% of our anticipated natural gas production hedged for the remainder of 2017. See Note 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at September 30, 2017.

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



	Nine Months Ended September 30,
(In thousands)	2017			2016
Net cash provided by operating activities	$	222,516		$	96,462
Net cash used in investing activities	(606,339		)	(297,596		)
Net cash provided by financing activities	191,117			204,968
Net change in cash	$	(192,706	)	$	3,834
Adjusted EBITDA⁽¹⁾attributable to Matador Resources Company shareholders	$	227,444		$	103,406

Net cash provided by operating activities increased $126.1 million to $222.5 million for the nine months ended September 30, 2017 from $96.5 million for the nine months ended September 30, 2016. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $210.7 million for the nine months ended September 30, 2017 from $85.4 million for the nine months ended September 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 increase of approximately $0.8 million in net cash provided by operating activities for the nine months ended September 30, 2017, as compared to the nine months ended September 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.

Net cash used in investing activities increased by $308.7 million to $606.3 million for the nine months ended September 30, 2017 from $297.6 million for the nine months ended September 30, 2016. This increase in net cash used in investing activities is primarily due to an increase of $229.1 million in oil and natural gas properties capital expenditures for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. Cash used for oil and natural gas properties capital expenditures for the nine months ended September 30, 2017 was primarily attributable to the acquisition of additional leasehold and mineral interests and to our operated drilling and completion activities in the Delaware Basin. A small portion of our capital expenditures for the nine months ended September 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 between the two periods related to restricted cash of approximately $52.0 million and an increase in cash used for other property and equipment of approximately $23.4 million primarily related to capital expenditures for San Mateo.

Net cash provided by financing activities decreased by $13.9 million to $191.1 million for the nine months ended September 30, 2017 from $205.0 million for the nine months ended September 30, 2016. During the nine months ended September 30, 2016, we received net proceeds from our March 2016 equity offering of $142.4 million ($141.5 million including cost to issue equity) and borrowed $65.0 million under our Credit Agreement. During the nine months ended September 30, 2017, we received net proceeds of $171.5 million related to contributions from the formation of the Joint Venture as well as $23.8 million related to net contributions from and distributions to the non-controlling interest owners of less-than-wholly-owned subsidiaries.

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.

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 September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2017			2016
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders	$	15,039		$	11,931		$	87,532		$	(201,575	)
Net income attributable to non-controlling interest in subsidiaries	2,940			116			8,034			209
Net income (loss)	17,979			12,047			95,566			(201,366		)
Interest expense	8,550			6,880			26,229			20,244
Total income tax provision (benefit)	—			(1,141		)	—			(1,141		)
Depletion, depreciation and amortization	47,800			30,015			123,066			90,185
Accretion of asset retirement obligations	323			276			937			828
Full-cost ceiling impairment	—			—			—			158,633
Unrealized loss (gain) on derivatives	12,372			(3,203		)	(21,449		)	30,261
Stock-based compensation expense	1,296			3,584			12,488			9,138
Net gain on asset sales and inventory impairment	(16		)	(1,073		)	(23		)	(3,140		)
Consolidated Adjusted EBITDA	88,304			47,385			236,814			103,642
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(3,471		)	(125		)	(9,370		)	(236		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	84,833		$	47,260		$	227,444		$	103,406



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2017			2016
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	101,274		$	46,862		$	222,516		$	96,462
Net change in operating assets and liabilities	(21,481		)	(4,909		)	(11,828		)	(11,024		)
Interest expense, net of non-cash portion	8,511			6,573			26,126			19,345
Current income tax provision (benefit)	—			(1,141		)	—			(1,141		)
Adjusted EBITDA attributable to non-controlling interest in subsidiaries	(3,471		)	(125		)	(9,370		)	(236		)
Adjusted EBITDA attributable to Matador Resources Company shareholders	$	84,833		$	47,260		$	227,444		$	103,406

The net income attributable to Matador Resources Company shareholders increased by $3.1 million to $15.0 million for the three months ended September 30, 2017, as compared to $11.9 million for the three months ended September 30, 2016. This increase in net income attributable to Matador Resources Company shareholders for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 is primarily attributable to the increase in oil and natural gas revenues of $51.9 million offset by (x) a decrease of $15.6 million from unrealized gain to unrealized loss on derivatives, (y) a $27.9 million increase in total expenses, including a $17.8 million increase in depletion, depreciation and amortization expenses, and (z) a $1.7 million increase in interest expense.

The net income attributable to Matador Resources Company shareholders increased by $289.1 million to $87.5 million for the nine months ended September 30, 2017, as compared to a net loss attributable to Matador Resources Company shareholders of $201.6 million for the nine months ended September 30, 2016. This increase in net income attributable to Matador Resources Company shareholders for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is primarily attributable to (i) the increase in oil and natural gas revenues of $167.2 million, (ii) the decrease of $158.6 million in the full-cost ceiling impairment and (iii) an increase of $51.7 million from unrealized loss to unrealized gain on derivatives, partially offset by (x) an increase in operating expenses of $64.7 million, excluding the full-cost ceiling impairment, (y) a $6.0 million increase in interest expense and (z) a decrease of $11.6 million from realized gain to realized loss on derivatives.

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 September 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 11 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.

We had the following material contractual obligations and commitments at September 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	23,245		2,498		5,087		5,377		10,283
Non-operated drilling commitments⁽³⁾	28,500		28,500		—		—		—
Drilling rig contracts⁽⁴⁾	36,117		24,253		11,864		—		—
Asset retirement obligations	23,923		618		578		3,781		18,946
Gas processing agreements with non-affiliates⁽⁵⁾	11,420		11,420		—		—		—
Gathering, processing and disposal agreements with San Mateo⁽⁶⁾	245,645		—		25,343		69,994		150,308
Natural gas plant engineering, procurement, construction and installation contract⁽⁷⁾	24,689		24,689		—		—		—
Total contractual cash obligations	$	969,360	$	91,978	$	42,872	$	79,973	$	754,537

For the three months ended September 30, 2017, oil prices averaged $48.20 per Bbl, ranging from a high of $52.22 per Bbl in late September to a low of $44.23 per Bbl in early July, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $46.25 per Bbl ($46.47 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended September 30, 2017, as compared to $42.57 per Bbl ($43.18 per Bbl including realized gains from oil derivatives) for the three months ended September 30, 2016. At November 6, 2017, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had increased significantly from the average price for the third quarter of 2017, settling at $57.35 per Bbl, which was also an increase as compared to $44.07 per Bbl at November 4, 2016.

For the three months ended September 30, 2017, natural gas prices averaged $2.95 per MMBtu, ranging from a high of approximately $3.15 per MMBtu in mid-September to a low of approximately $2.77 per MMBtu in early August, 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 $3.42 per Mcf ($3.42 per Mcf as a result of no realized gains or losses from natural gas derivatives) for our natural gas production (including revenues attributable to natural gas liquids) for the three months ended September 30, 2017, as compared to $3.08 per Mcf ($3.08 per Mcf, including minimal realized gains from natural gas derivatives) for the three months ended September 30, 2016. At November 6, 2017, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had increased from the average price for the third quarter of 2017, settling at $3.13 per MMBtu, which was also an increase as compared to $2.77 per MMBtu at November 4, 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 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 experienced price increases from our service providers for some of the products and services we use in our drilling, completion and production operations in 2017. 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 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 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 that 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 September 30, 2017, Comerica Bank, RBC, 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 9 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at September 30, 2017. Such information is incorporated herein by reference.

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 September 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.

During the three months ended September 30, 2017, we completed the implementation of new accounting and land administration software applications. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change, including procedures to preserve the integrity of the data converted during the application implementations. Additionally, we provided training related to these applications to individuals using the applications to carry out their job responsibilities. We believe the new applications will enhance our internal control over financial reporting due to enhanced automation and integration of related processes. We are modifying the design and documentation of internal control processes and procedures relating to the new applications to complement and supplement existing internal control documentation. The implementation of the new applications was not undertaken in response to any deficiencies in our internal control over financial reporting. Testing of the controls related to the new applications and related accounting and land administration functions is ongoing and is included in the scope of our assessment of our internal control over financial reporting for the three months ended September 30, 2017. We plan to monitor controls within and around the applications to provide reasonable assurance that controls are effective.

During the quarter ended September 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
July 1, 2017 to July 31, 2017	1,328	$	22.70	—	—
August 1, 2017 to August 31, 2017	34,748	23.32		—	—
September 1, 2017 to September 30, 2017	181	26.11		—	—
Total	36,257	$	23.31	—	—



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)



Large accelerated filer	x	Accelerated filer	¨

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

		Emerging growth company	¨



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements - Unaudited	3
Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016	3
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	4
Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2017	5
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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	24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	42
Item 4. Controls and Procedures	42
PART II — OTHER INFORMATION	43
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 6. Exhibits	43
SIGNATURES	44



Commodity	Calculation Period	Notional Quantity (Bbl or Gal)	Fixed Price ($/Bbl or $/Gal)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	01/01/2018 - 12/31/2018	5,220,000	$	(1.02	)	$	(2,337	)
NGL	10/01/2017 - 12/31/2017	900,000	$	0.89		(8		)
Total open swap contracts						$	(2,345	)
Total open derivative financial instruments						$	(3,505	)



		MATADOR RESOURCES COMPANY

Date: November 9, 2017	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer



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



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


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


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


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



	Fair Value Measurements at September 30, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Oil, natural gas and NGL derivatives	$	—	$	345		$	—	$	345
Oil, natural gas and NGL derivatives	—		(3,850		)	—		(3,850		)
Total	$	—	$	(3,505	)	$	—	$	(3,505	)



	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	)


(1)	Includes depletion, depreciation and amortization expenses of $46.1 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 $2.9 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $17.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.


(2)	Includes $116,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(2)	Includes $8.0 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $35.8 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.


(2)	Includes $209,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


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


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


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


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


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


•	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;


•	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;


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


•	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.


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


(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.


(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.