Matador Resources Co - Quarter Report: 2016 March (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________________

FORM 10-Q

_________________________________________________________



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

For the quarterly period ended March 31, 2016



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

For the transition period from to

Commission File Number 001-35410

_________________________________________________________

Matador Resources Company

(Exact name of registrant as specified in its charter)

_________________________________________________________



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

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

(972) 371-5200

(Registrant’s telephone number, including area code)

_________________________________________________________

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

As of May 5, 2016, there were 93,283,434 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

Table of Contents

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2016

INDEX



	Page
PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements - Unaudited	3
Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015	3
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015	4
Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2016	5
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3. Quantitative and Qualitative Disclosures About Market Risk	30
Item 4. Controls and Procedures	31
PART II — OTHER INFORMATION	32
Item 1. Legal Proceedings	32
Item 1A. Risk Factors	32
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6. Exhibits	32
SIGNATURES	33

Table of Contents

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements — Unaudited

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data)



	March 31, 2016			December 31, 2015
ASSETS
Current assets
Cash	$	118,329		$	16,732
Restricted cash	510			44,357
Accounts receivable
Oil and natural gas revenues	14,748			16,616
Joint interest billings	16,807			16,999
Other	5,548			10,794
Derivative instruments	11,966			16,284
Lease and well equipment inventory	1,928			2,022
Prepaid expenses	3,250			3,203
Total current assets	173,086			127,007
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,192,053			2,122,174
Unproved and unevaluated	381,915			387,504
Other property and equipment	108,731			86,387
Less accumulated depletion, depreciation and amortization	(1,693,044		)	(1,583,659		)
Net property and equipment	989,655			1,012,406
Other assets
Derivative instruments	60			—
Other assets	1,351			1,448
Total other assets	1,411			1,448
Total assets	$	1,164,152		$	1,140,861
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	5,930		$	10,966
Accrued liabilities	84,495			92,369
Royalties payable	12,518			16,493
Amounts due to affiliates	3,898			5,670
Derivative instruments	299			—
Advances from joint interest owners	3,225			700
Deferred gain on plant sale	5,367			4,830
Amounts due to joint ventures	3,115			2,793
Income taxes payable	385			2,848
Other current liabilities	161			161
Total current liabilities	119,393			136,830
Long-term liabilities
Senior unsecured notes payable	391,553			391,254
Asset retirement obligations	17,177			15,166
Amounts due to joint ventures	3,634			3,956
Derivative instruments	2,282			—
Deferred gain on plant sale	100,896			102,506
Other long-term liabilities	4,065			2,190
Total long-term liabilities	519,607			515,072
Commitments and contingencies (Note 10)
Shareholders’ equity
Common stock - $0.01 par value, 120,000,000 shares authorized; 93,327,432 and 85,567,021 shares issued; and 93,271,423 and 85,564,435 shares outstanding, respectively	933			856
Additional paid-in capital	1,169,860			1,026,077
Retained deficit	(646,584		)	(538,930		)
Total Matador Resources Company shareholders’ equity	524,209			488,003
Non-controlling interest in subsidiaries	943			956
Total shareholders’ equity	525,152			488,959
Total liabilities and shareholders’ equity	$	1,164,152		$	1,140,861

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data)



	Three Months Ended March 31,
	2016			2015
Revenues
Oil and natural gas revenues	$	43,926		$	62,465
Realized gain on derivatives	7,063			18,504
Unrealized loss on derivatives	(6,839		)	(8,557		)
Total revenues	44,150			72,412
Expenses
Production taxes and marketing	7,902			7,049
Lease operating	15,489			13,046
Depletion, depreciation and amortization	28,923			46,470
Accretion of asset retirement obligations	264			112
Full-cost ceiling impairment	80,462			67,127
General and administrative	13,163			13,413
Total expenses	146,203			147,217
Operating loss	(102,053		)	(74,805		)
Other income (expense)
Net gain (loss) on asset sales and inventory impairment	1,065			(97		)
Interest expense	(7,197		)	(2,070		)
Interest and other income	518			384
Total other expense	(5,614		)	(1,783		)
Loss before income taxes	(107,667		)	(76,588		)
Income tax (benefit) provision
Deferred	—			(26,390		)
Total income tax (benefit) provision	—			(26,390		)
Net loss	(107,667		)	(50,198		)
Net loss (income) attributable to non-controlling interest in subsidiaries	13			(36		)
Net loss attributable to Matador Resources Company shareholders	$	(107,654	)	$	(50,234	)
Earnings (loss) per common share
Basic	$	(1.26	)	$	(0.68	)
Diluted	$	(1.26	)	$	(0.68	)
Weighted average common shares outstanding
Basic	85,305			73,819
Diluted	85,305			73,819

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY - UNAUDITED

(In thousands)

For the Three Months Ended March 31, 2016



													Total shareholders’ equity attributable to Matador Resources Company


																Non-controlling interest in subsidiary			Total shareholders’ equity
	Common Stock			Additional paid-in capital			Retained deficit			Treasury Stock
	Shares	Amount		Additional paid-in capital			Retained deficit			Shares	Amount
Balance at January 1, 2016	85,567	$	856	$	1,026,077		$	(538,930	)	2	$	—	$	488,003		$	956		$	488,959
Issuance of common stock	7,500	75		142,275			—			—	—		142,350			—			142,350
Cost to issue equity	—	—		(830		)	—			—	—		(830		)	—			(830		)
Stock-based compensation expense related to equity-based awards	—	—		2,340			—			—	—		2,340			—			2,340
Stock options exercised	2	—		—			—			—	—		—			—			—
Restricted stock issued	249	2		(2		)	—			—	—		—			—			—
Restricted stock forfeited	—	—		—			—			54	—		—			—			—
Vesting of restricted stock units	9	—		—			—			—	—		—			—			—
Current period net loss	—	—		—			(107,654		)	—	—		(107,654		)	(13		)	(107,667		)
Balance at March 31, 2016	93,327	$	933	$	1,169,860		$	(646,584	)	56	$	—	$	524,209		$	943		$	525,152

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

Table of Contents

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED

(In thousands)



	Three Months Ended March 31,
	2016			2015
Operating activities
Net loss	$	(107,667	)	$	(50,198	)
Adjustments to reconcile net loss to net cash provided by operating activities
Unrealized loss on derivatives	6,839			8,557
Depletion, depreciation and amortization	28,923			46,470
Accretion of asset retirement obligations	264			112
Full-cost ceiling impairment	80,462			67,127
Stock-based compensation expense	2,243			2,337
Deferred income tax (benefit) provision	—			(26,390		)
Amortization of debt issuance cost	300			—
Net (gain) loss on asset sales and inventory impairment	(1,065		)	97
Changes in operating assets and liabilities
Accounts receivable	7,307			2,140
Lease and well equipment inventory	150			(112		)
Prepaid expenses	(47		)	(364		)
Other assets	97			193
Accounts payable, accrued liabilities and other current liabilities	2,591			45,703
Royalties payable	(3,975		)	(2,907		)
Advances from joint interest owners	2,524			1,378
Income taxes payable	(2,463		)	(444		)
Other long-term liabilities	1,875			(353		)
Net cash provided by operating activities	18,358			93,346
Investing activities
Oil and natural gas properties capital expenditures	(74,370		)	(127,440		)
Expenditures for other property and equipment	(27,409		)	(14,241		)
Business combination, net of cash acquired	—			(24,028		)
Restricted cash	43,337			—
Restricted cash in less-than-wholly-owned subsidiaries	510			(383		)
Net cash used in investing activities	(57,932		)	(166,092		)
Financing activities
Borrowings under Credit Agreement	—			70,000
Proceeds from issuance of common stock	142,350			—
Cost to issue equity	(614		)	—
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	—			450
Taxes paid related to net share settlement of stock-based compensation	(565		)	(50		)
Net cash provided by financing activities	141,171			70,400
Increase (decrease) in cash	101,597			(2,346		)
Cash at beginning of period	16,732			8,407
Cash at end of period	$	118,329		$	6,061

Supplemental disclosures of cash flow information (Note 11)

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED

NOTE 1 - NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The interim unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC (the “Annual Report”). The Company proportionately consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments, consisting only of normal, recurring adjustments, which are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of March 31, 2016. Amounts as of December 31, 2015 are derived from the audited consolidated financial statements in the Annual Report.

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

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter which 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. Due primarily to declines in oil and natural gas prices, the capitalized costs of oil and natural gas properties exceeded the cost center ceiling, and as a result, the Company recorded an impairment charge of $80.5 million to its net capitalized costs at March 31, 2016. At March 31, 2015, the Company recorded an impairment charge of $67.1 million to its net capitalized costs. These charges are reflected in the Company’s interim unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015, respectively.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheet, as well as the corresponding consolidated shareholders’ equity, but it has no impact on the Company’s consolidated net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

The Company capitalized approximately $2.0 million and $1.6 million of its general and administrative costs for the three months ended March 31, 2016 and 2015, respectively, and approximately $0.4 million and $1.0 million of its interest expense for the three months ended March 31, 2016 and 2015, respectively.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

Earnings (Loss) Per Common Share

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

The following table sets forth the computation of diluted weighted average common shares outstanding for the three months ended March 31, 2016 and 2015 (in thousands).



	Three Months Ended March 31,
	2016	2015
Weighted average common shares outstanding
Basic	85,305	73,819
Dilutive effect of options, restricted stock units and preferred shares	—	—
Diluted weighted average common shares outstanding	85,305	73,819

A total of 3.0 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 three months ended March 31, 2016 because their effects were anti-dilutive. A total of 2.5 million options to purchase shares of the Company’s common stock, 0.2 million restricted stock units and 150,000 preferred shares were excluded from the diluted weighted average common shares outstanding for the three months ended March 31, 2015 because their effects were anti-dilutive.

Additionally, 1.0 million and 0.8 million restricted shares, which are participating securities, were excluded from both basic and diluted weighted average common shares outstanding for the three months ended March 31, 2016 and 2015, respectively, as the security holders do not have the obligation to share in the losses of the Company.

Recent Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. In addition, 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. ASU 2014-09 will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted for periods beginning after December 15, 2016. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, of the adoption of this ASU 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. ASU 2016-02 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.

Compensation - Stock Compensation. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718), which simplifies several aspects of the accounting for employee share-based payment transactions, including accounting for income tax, forfeitures, statutory tax withholding requirements, classifications of awards as either equity or liability and classification of taxes in the statement of cash flows. The amended guidance also requires an entity to record excess tax benefits and deficiencies in the income statement. The amended guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and plans to adopt this ASU in the second quarter of 2016.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 3 - EQUITY

On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million, the Company received net proceeds of approximately $141.5 million, which are being used for general corporate purposes, including to fund a portion of the Company’s current and future capital expenditures.

NOTE 4 - ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the three months ended March 31, 2016 (in thousands).




Beginning asset retirement obligations	$	15,420
Liabilities incurred during period	303
Revisions in estimated cash flows	1,238
Accretion expense	264
Ending asset retirement obligations	17,225
Less: current asset retirement obligations⁽¹⁾	(48		)
Long-term asset retirement obligations	$	17,177

_______________


(1)	Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at March 31, 2016.

NOTE 5 - DEBT

At March 31, 2016 and May 5, 2016, the Company had $400 million of outstanding 6.875% senior notes due 2023 (the “Notes”), no borrowings outstanding under the Company’s revolving credit agreement (the “Credit Agreement”) and approximately $0.6 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. At March 31, 2016, the borrowing base available under the Credit Agreement was $375.0 million. On May 3, 2016, the borrowing base under the Credit Agreement was reduced to $300.0 million from $375.0 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at December 31, 2015.

In the event of a borrowing base increase, 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 borrowing base increase. Total deferred loan costs associated with the Credit Agreement were $1.7 million at March 31, 2016, and these costs are being amortized over the term of the agreement, which approximates the 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.

At March 31, 2016, the Company believes that it was in compliance with the terms of its Credit Agreement.

On April 14, 2015, the Company issued the Notes, which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At March 31, 2016, all of the Guarantor Subsidiaries are 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries are minor. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan.

NOTE 6 - INCOME TAXES

At March 31, 2016, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the full cost ceiling impairment charges recorded; as a result, the Company established a valuation allowance

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 6 - INCOME TAXES - Continued

against most of the deferred tax assets beginning in the third quarter of 2015. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized.

The total income tax benefit for the three months ended March 31, 2015 differed from amounts computed by applying the U.S. federal statutory tax rate to loss before income taxes due primarily to the impact of permanent differences between book and taxable income.

NOTE 7 - STOCK-BASED COMPENSATION

In February 2016, the Company granted awards of 243,428 shares of restricted stock and options to purchase 608,287 shares of the Company’s common stock at an exercise price of $15.00 per share to certain of its employees. The fair value of these awards was approximately $7.0 million. All of these awards vest on the three-year anniversary of the grant date of these awards.

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS

At March 31, 2016, the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2016 and 2017.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at March 31, 2016.



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	04/01/2016 - 12/31/2016	2,070,000	$	42.48	$	61.16	$	7,998
Oil	01/01/2017 - 12/31/2017	1,560,000	$	38.62	$	47.62	(2,571		)
Natural Gas	04/01/2016 - 12/31/2016	9,000,000	$	2.60	$	3.53	4,130
Natural Gas	01/01/2017 - 12/31/2017	9,000,000	$	2.27	$	3.50	(112		)
Total open derivative financial instruments							$	9,445

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

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 March 31, 2016 and December 31, 2015 (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
March 31, 2016
Current assets	$	16,196		$	(4,230	)	$	11,966
Other assets	5,442			(5,382		)	60
Current liabilities	(4,529		)	4,230			(299		)
Other liabilities	(7,664		)	5,382			(2,282		)
Total	$	9,445		$	—		$	9,445
December 31, 2015
Current assets	$	16,767		$	(483	)	$	16,284
Current liabilities	(483		)	483			—
Total	$	16,284		$	—		$	16,284

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 March 31,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2016			2015
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	5,464		$	14,433
Natural Gas	Revenues: Realized gain on derivatives	1,599			3,600
Natural Gas Liquids	Revenues: Realized gain on derivatives	—			471
Realized gain on derivatives		7,063			18,504
Oil	Revenues: Unrealized loss on derivatives	(7,654		)	(6,464		)
Natural Gas	Revenues: Unrealized gain (loss) on derivatives	815			(1,563		)
Natural Gas Liquids	Revenues: Unrealized loss on derivatives	—			(530		)
Unrealized loss on derivatives		(6,839		)	(8,557		)
Total		$	224		$	9,947

NOTE 9 - FAIR VALUE MEASUREMENTS

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


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

Level 2

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

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 9 - FAIR VALUE MEASUREMENTS - Continued

term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.


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

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

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of March 31, 2016 and December 31, 2015 (in thousands).



	Fair Value Measurements at March 31, 2016 using
Description	Level 1		Level 2	Level 3		Total
Assets
Oil and natural gas derivatives	$	—	9,445	$	—	9,445
Total	$	—	9,445	$	—	9,445



	Fair Value Measurements at December 31, 2015 using
Description	Level 1		Level 2		Level 3		Total
Assets
Oil and natural gas derivatives	$	—	$	16,284	$	—	$	16,284
Total	$	—	$	16,284	$	—	$	16,284

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

Other Fair Value Measurements

At March 31, 2016 and December 31, 2015, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures, income taxes payable and other current liabilities approximated their fair values due to their short-term maturities.

At March 31, 2016 and December 31, 2015, the fair value of the Notes was $382.0 million and $381.0 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Natural Gas and NGL Processing and Transportation Commitments

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

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company’s remaining aggregate undiscounted minimum commitments under this agreement are $2.5 million at March 31, 2016. The Company paid $0.9 million and $1.3 million in processing and transportation fees under this agreement during the three months ended March 31, 2016 and 2015.

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 through the counterparty’s gathering system for processing at the counterparty’s facility. Under this agreement, if the Company does not meet the volume commitment for gathering and processing at the facility 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 gathering 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 March 31, 2016, the total deficiency fee required to be paid would be approximately $8.9 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 $2.0 million in processing and gathering fees under this agreement during the three months ended March 31, 2016. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plant.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for one year or less, although the Company has entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were until recently experiencing heavy demand for drilling rigs. The Company would incur a termination obligation if the Company elected to terminate a contract and the drilling contractor were unable to secure 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 $43.2 million at March 31, 2016.

The Company entered into an agreement in late 2015 with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in the Rustler Breaks prospect area in Eddy County, New Mexico. The plant is expected to process a portion of the Company’s natural gas produced from certain of its wells in the Delaware Basin, as well as third-party natural gas once the plant is completed and placed in service, which is scheduled to occur in the third quarter of 2016. At March 31, 2016, total remaining commitments under this contract were $8.6 million, and the Company made payments totaling $13.5 million during the three months ended March 31, 2016.

At March 31, 2016, the Company had agreed to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed, the Company will have undiscounted minimum outstanding aggregate

Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -

UNAUDITED - CONTINUED

NOTE 10 - COMMITMENTS AND CONTINGENCIES - Continued

commitments for its participation in these wells of approximately $4.7 million at March 31, 2016, which the Company expects to incur within the next few months.

Legal Proceedings

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

NOTE 11 - SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at March 31, 2016 and December 31, 2015 (in thousands).



	March 31, 2016		December 31, 2015
Accrued evaluated and unproved and unevaluated property costs	$	41,423	$	54,586
Accrued support equipment and facilities costs	10,303		17,393
Accrued cost to issue equity	216		—
Accrued lease operating expenses	10,066		7,743
Accrued interest on debt	12,681		5,806
Accrued asset retirement obligations	48		254
Accrued partners’ share of joint interest charges	4,712		4,565
Accrued stock-based compensation	872		—
Other	4,174		2,022
Total accrued liabilities	$	84,495	$	92,369

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the three months ended March 31, 2016 and 2015 (in thousands).



	Three Months Ended March 31,
	2016			2015
Cash paid for interest expense, net of amounts capitalized	$	—		$	1,990
Asset retirement obligations related to mineral properties	$	1,606		$	1,507
Asset retirement obligations related to support equipment and facilities	$	(65	)	$	32
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	$	(11,622	)	$	8,654
(Decrease) increase in liabilities for support equipment and facilities	$	(5,000	)	$	6,865
Increase in liabilities for accrued cost to issue equity	$	216		$	—
Issuance of restricted stock units for Board and advisor services	$	138		$	142
Issuance of common stock for advisor services	$	—		$	4
Stock-based compensation expense recognized as liability	$	(98	)	$	263
Transfer of inventory from oil and natural gas properties	$	64		$	310

Table of Contents

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our interim unaudited condensed consolidated financial statements and related notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

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

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

Cautionary Note Regarding Forward-Looking Statements

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

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


•	our business strategy;


•	our reserves;


•	our technology;


•	our cash flows and liquidity;


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


•	our oil and natural gas realized prices;


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


•	the availability of drilling and production equipment;


•	the availability of oil field labor;


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


•	the availability and terms of capital;


•	our drilling of wells;


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


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


•	our marketing of oil and natural gas;


•	our exploitation projects or property acquisitions;


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

Table of Contents


•	our ability to construct and operate midstream facilities;


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


•	general economic conditions;


•	competition in the oil and natural gas industry;


•	the effectiveness of our risk management and hedging activities;


•	environmental liabilities;


•	counterparty credit risk;


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


•	our future operating results;


•	estimated future reserves and the present value thereof; and


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

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

You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

Overview

We are an independent energy company 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.

First Quarter Highlights

For the three months ended March 31, 2016, our total oil equivalent production was 2.17 million BOE and our average daily oil equivalent production was 23,846 BOE per day, of which 11,473 Bbl per day, or 48%, was oil and 74.2 MMcf per day, or 52%, was natural gas. Our total oil equivalent production of 2.17 million BOE for the three months ended March 31, 2016 increased 3% year-over-year from 2.12 million BOE for the three months ended March 31, 2015. We were operating three drilling rigs, all in the Delaware Basin, during the first quarter of 2016, as compared to five operated drilling rigs, three in the Delaware Basin and two in the Eagle Ford shale, during the first quarter of 2015.

During the first quarter of 2016, our oil and natural gas revenues were $43.9 million, a decrease of 30% from oil and natural gas revenues of $62.5 million during the first quarter of 2015. Our oil revenues and natural gas revenues decreased 31% and 26% to approximately $30.2 million and $13.8 million, respectively, as a result of significantly lower oil and natural gas prices realized for the first quarter of 2016, as compared to $43.7 million and $18.7 million, respectively, for the first quarter of 2015. We realized weighted average oil and natural gas prices of $28.89 per Bbl and $2.04 per Mcf, respectively, in the first quarter of 2016 as compared to weighted average oil and natural gas prices of $43.37 per Bbl and $2.82 per Mcf, respectively, realized in the first quarter of 2015. This decrease in oil and natural gas revenues was somewhat mitigated by the 3% increase in our oil production to 1.04 million Bbl in the first quarter of 2016, as compared to 1.01 million Bbl produced in the first quarter of 2015, and the 2% increase in our natural gas production to 6.8 Bcf in the first quarter of 2016, as compared to 6.6 Bcf in the first quarter of 2015. The increase in oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not drilled and completed any new operated wells since early in the second quarter of 2015. The increase in natural gas production was also primarily a result of our ongoing delineation and development drilling in the Delaware Basin and was achieved despite natural gas production being impacted negatively by flooding in Northwest Louisiana during the first quarter of 2016, which resulted in a portion of our Haynesville and Cotton Valley natural gas production, including both operated and non-operated properties in the Elm Grove area, being shut-in for two to three weeks. For the three months ended March 31, 2016, our Adjusted EBITDA was $17.2 million, a decrease of 66% from Adjusted EBITDA of $50.1 million during the three months ended March 31, 2015.

Table of Contents

Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for the first quarter of 2016, see “— Results of Operations” below.

During the first quarter of 2016, we operated three drilling rigs in the Delaware Basin. Early in the first quarter, two of these rigs were operating in our Wolf prospect area in Loving County, Texas and one was operating in our Rustler Breaks prospect area in Eddy County, New Mexico. In late February, one of these rigs was moved to our Rustler Breaks prospect area, and since that time and at May 5, 2016, two rigs were operating in our Rustler Breaks prospect area and one rig was operating in our Wolf prospect area.

One of the rigs operating in our Wolf prospect area early in the first quarter drilled a four-well pad in “batch” mode (the Dick Jay pad), testing the Wolfcamp A-X, the Wolfcamp A-Y, the Wolfcamp A-Lower and the Second Bone Spring. Only one of these four wells—the Dick Jay 92-TTT-B01 WF #124, the Second Bone Spring completion—was placed on production in the first quarter of 2016. The remaining three wells were completed and placed on production during April 2016. The second rig drilled a three-well pad in “batch” mode (the Dorothy White pad), with two wells testing the Wolfcamp A-X and one well testing the Wolfcamp A-Y. Each of these three wells was completed and placed on production in mid-to-late April. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. In addition, we participated in several non-operated Haynesville shale wells placed on production by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) during the first quarter of 2016 but expect minimal non-operated activity in the Haynesville shale from Chesapeake and our other partners throughout the remainder of 2016. At March 31, 2016, we had incurred $87.1 million, or approximately 27%, of our 2016 capital expenditure budget of $325.0 million.

We continue to make progress in reducing drilling times and well costs for both Wolfcamp and Bone Spring horizontal wells in the Wolf prospect area in Loving County, Texas. Our most recently drilled Wolfcamp well, the Dorothy White 82-TTT-B33 WF #203H, was drilled from spud to total depth of 15,550 feet in 17.3 days, as compared to average drilling times of 43 days in 2014 for similar depths. The Dick Jay 92-TTT-B01 WF #124H was our fastest Second Bone Spring well drilled to date in the Wolf prospect area at approximately 12.6 days from spud to total depth of 14,883 feet. In addition, our drilling engineers were able to eliminate a second intermediate casing string typically used when drilling the Second Bone Spring in the Wolf prospect area. Not only did eliminating this casing string save approximately $650,000 in well costs, but it also provides for larger casing to be set through the lateral, thereby reducing hydraulic horsepower costs during fracturing operations and enhancing the number of artificial lift options available to us in the future. Furthermore, by drilling multiple wells in “batch” mode, we expect to be able to reduce well costs even further. As an example, we estimate that we saved up to $400,000 in drilling costs per well, or a total of approximately $1.6 million, by drilling the four Dick Jay wells in “batch” mode on a single pad. Completion costs have also continued to improve significantly as a result of our efficiencies, technology and reduced service costs.

During the first quarter of 2016, we began producing oil and natural gas from six gross (3.2 net) wells in the Delaware Basin, including three gross (2.8 net) operated wells and three gross (0.4 net) non-operated wells, throughout our various prospect areas. As of the end of the first quarter of 2016, we had drilled an additional ten wells that were in the process of completion or awaiting completion, including five Wolfcamp A-XY wells and a lower Wolfcamp A well in our Wolf prospect area in Loving County, Texas and two Wolfcamp A-XY wells and two Wolfcamp B wells in our Rustler Breaks prospect area in Eddy County, New Mexico. As a result of our ongoing drilling and completion operations in these prospect areas, our Delaware Basin production has continued to increase over the past twelve months. Our total Delaware Basin production for the first quarter of 2016 was 9,958 BOE per day, consisting of 7,172 Bbl of oil per day and 16.7 MMcf of natural gas per day, a 2.8-fold increase from production of 3,546 BOE per day, consisting of 2,467 Bbl of oil per day and 6.5 MMcf of natural gas per day, in the first quarter of 2015. The Delaware Basin contributed approximately 63% of our daily oil production and approximately 22% of our daily natural gas production in the first quarter of 2016, as compared to only approximately 22% of our daily oil production and approximately 9% of our daily natural gas production in the first quarter of 2015.

In the Wolf prospect area, the Dick Jay 92-TTT-B01 WF #124H, the Second Bone Spring test, flowed approximately 1,100 BOE per day (67% oil), which exceeded our expectations and was a significant improvement over our first Second Bone Spring test in this area. We pumped a larger fracture treatment on the Dick Jay 92-TTT-B01 WF #124H well, using 40 barrels per foot of fracturing fluid and 2,000 pounds of 20/40 sand per foot of lateral, compared to our previous Second Bone Spring completion in the Wolf prospect area, which used only 20 barrels per foot of fracturing fluid and about 1,300 pounds of 30/50 sand per foot of lateral. We also ran flow-through plugs with dissolvable balls for the first time on this well; these dissolvable balls performed well, eliminating the need for the plugs to be drilled out following completion, thus saving another $40,000 in well costs. Total costs for this well were approximately $4.4 million, some of which was attributable to extended flowback equipment used to test the Second Bone Spring completion while the deeper Wolfcamp laterals were being completed. In the near future, we estimate that we should be able to drill, complete and equip Second Bone Spring wells in this area for under $4 million.

Table of Contents

In our Twin Lakes prospect area in northern Lea County, New Mexico, we drilled an initial data collection well, the Olivine State 5-16S-37E TL #1, during the fourth quarter of 2015. This was a vertical pilot hole drilled for the purpose of collecting whole core and a detailed suite of geophysical logs to assist us in determining the landing target for our initial horizontal test of the Wolfcamp D interval at Twin Lakes. We collected about 400 feet of whole core throughout much of the Wolfcamp D interval, and at March 31, 2016, the core data and well logs were undergoing detailed description and analysis by both our geoscience staff and third-party vendors. We plan to drill our Wolfcamp D horizontal test in the fourth quarter of 2016. The Olivine State 5-16S-37E TL #1 vertical pilot hole was drilled through the Wolfcamp D and into and through the Strawn formation below. The Strawn interval at about 11,500 feet is a complex carbonate formation that has previously produced significant quantities of oil and natural gas in the Twin Lakes area. Upon drilling through the Strawn interval, our geoscience staff analyzed the well logs taken across the interval and determined that there was the potential for a Strawn test. As a result, the Olivine State 5-16S-37E TL #1 was perforated and completed in the Strawn interval with a small acid treatment during the first quarter of 2016. This well flowed 691 BOE per day (84% oil) during a 24-hour initial potential test, consisting of 579 Bbl of oil per day and 0.7 MMcf of natural gas per day, at a flowing surface pressure of 350 pounds per square inch (“psi”) on a 32/64 inch choke. Given the positive results from this Strawn test, we plan to produce the Olivine State 5-16S-37E TL #1 rather than plug back, kick off and drill a horizontal Wolfcamp D test from this vertical wellbore as originally anticipated. We expect to drill a new horizontal well on the same pad to test the Wolfcamp D interval later in 2016.

We participated in one new, non-operated well on our Arrowhead acreage during the first quarter of 2016. This well, the Yates Petroleum Corporation Baroque “BTQ” Federal Com #1H well, tested at rates averaging approximately 1,300 BOE per day (including approximately 1,100 Bbl of oil per day and 1.2 MMcf of natural gas per day) beginning in late March 2016. This well is located in the eastern portion of our Arrowhead prospect area in Eddy County, New Mexico. We own a 9.5% working interest in this well, which provides yet another indication of the prospectivity of our northern Delaware Basin acreage.

We also participated in 12 gross (2.0 net) non-operated Haynesville shale wells that were placed on production during the first quarter of 2016, including nine gross (1.9 net) wells operated by Chesapeake on our Elm Grove properties in southern Caddo Parish, Louisiana. These nine wells came on production at an average of 13.5 MMcf per day and were drilled and completed for an average of under $7 million. We did not complete or begin producing oil and natural gas from any new operated Eagle Ford wells during the first quarter of 2016, and at May 5, 2016, we had no plans to drill any operated wells in the Eagle Ford during 2016.

At December 31, 2015, we held approximately 157,100 gross (88,800 net) acres in Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. Between January 1, 2016 and May 3, 2016, we added approximately 2,500 gross (2,100 net) acres in the Delaware Basin. As a result, at May 3, 2016 our total acreage position in Southeast New Mexico and West Texas was approximately 158,000 gross (90,200 net) acres, almost all of which is in the Delaware Basin. We plan to continue our leasing and acquisition efforts in the Delaware Basin during the remainder of 2016 and may also consider acquiring acreage in the Eagle Ford shale and Haynesville shale as strategic opportunities are identified.

On March 11, 2016, we completed a public offering of 7,500,000 shares of our common stock. After deducting offering costs totaling approximately $0.8 million, we received net proceeds of approximately $141.5 million. See Note 3 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more details regarding this offering.

On May 3, 2016, the borrowing base under our third amended and restated credit agreement (the “Credit Agreement”) was reduced to $300.0 million from $375.0 million based on our lenders’ review of our proved oil and natural gas reserves at December 31, 2015 using commodity price estimates prescribed by the lenders. The borrowing base reduction was primarily attributable to the significant decline in oil and natural gas prices experienced since July 2014. All other provisions of our Credit Agreement remain unchanged. At March 31, 2016 and May 5, 2016, we had no borrowings outstanding under our Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to our Credit Agreement. See Note 5 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more details regarding our Credit Agreement.

Estimated Proved Reserves

The following table sets forth our estimated total proved oil and natural gas reserves at March 31, 2016, December 31, 2015 and March 31, 2015. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our

Table of Contents

properties, nor do they include any consideration that would be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total proved reserves are estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.



	March 31, 2016			December 31, 2015			March 31, 2015
Estimated Proved Reserves Data: ⁽¹⁾⁽²⁾
Estimated proved reserves:
Oil (MBbl)⁽³⁾	50,718			45,644			32,506
Natural Gas (Bcf)⁽⁴⁾	236.7			236.9			280.5
Total (MBOE)⁽⁵⁾	90,168			85,127			79,262
Estimated proved developed reserves:
Oil (MBbl)⁽³⁾	16,818			17,129			15,889
Natural Gas (Bcf)⁽⁴⁾	96.9			101.4			104.7
Total (MBOE)⁽⁵⁾	32,968			34,037			33,340
Percent developed	36.6		%	40.0		%	42.1		%
Estimated proved undeveloped reserves:
Oil (MBbl)⁽³⁾	33,900			28,515			16,617
Natural Gas (Bcf)⁽⁴⁾	139.8			135.5			175.8
Total (MBOE)⁽⁵⁾	57,200			51,090			45,922
PV-10⁽⁶⁾ (in millions)	$	501.9		$	541.6		$	1,070.1
Standardized Measure⁽⁷⁾ (in millions)	$	495.6		$	529.2		$	949.2

_______________


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

(2)

Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from April 2015 through March 2016 were $42.77 per Bbl for oil and $2.40 per MMBtu for natural gas, for the period from January 2015 through December 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas and for the period from April 2014 through March 2015 were $79.21 per Bbl for oil and $3.88 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.


(3)	One thousand barrels of oil.


(4)	One billion cubic feet of natural gas.


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

(6)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at March 31, 2016, December 31, 2015 and March 31, 2015 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at March 31, 2016, December 31, 2015 and March 31, 2015 were, in millions, $6.3, $12.4 and $120.9, respectively.


(7)	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.

Table of Contents

At March 31, 2016, our estimated total proved oil and natural gas reserves were 90.2 million BOE, an all-time high for Matador, including 50.7 million Bbl of oil and 236.7 Bcf of natural gas, with a PV-10 of $501.9 million and a Standardized Measure of $495.6 million. At December 31, 2015, our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, and at March 31, 2015, our estimated total proved oil and natural gas reserves were 79.3 million BOE, including 32.5 million Bbl of oil and 280.5 Bcf of natural gas. Our proved oil reserves of 50.7 million Bbl at March 31, 2016, also an all-time high for Matador, increased 11%, as compared to 45.6 million Bbl at December 31, 2015, and increased 56%, as compared to 32.5 million Bbl at March 31, 2015. At March 31, 2016, approximately 37% of our total proved reserves were proved developed reserves, 56% of our total proved reserves were oil and 44% of our total proved reserves were natural gas. Primarily as a result of the continued decline in commodity prices used to estimate proved reserves at March 31, 2016, certain of our proved undeveloped reserves, and in particular proved undeveloped natural gas reserves in portions of the Haynesville shale, were reclassified to contingent resources and are no longer considered proved reserves under applicable SEC guidelines.

As a result of our drilling, completion and delineation activities in West Texas and Southeast New Mexico since 2014, our Delaware Basin oil and natural gas reserves continue to become a more significant component of our total oil and natural gas reserves. Our estimated Delaware Basin proved oil and natural gas reserves have increased approximately 2.6-fold from 22.9 million BOE at March 31, 2015, or 29% of our total proved oil and natural gas reserves, including 15.0 million Bbl of oil and 47.6 Bcf of natural gas, to 59.6 million BOE, or 66% of our total proved oil and natural gas reserves, including 37.7 million Bbl of oil and 131.6 Bcf of natural gas, at March 31, 2016.

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

Critical Accounting Policies

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

Recent Accounting Pronouncements

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

Table of Contents

Results of Operations

Revenues

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



	Three Months Ended March 31,
	2016			2015
Operating Data:
Revenues (in thousands):⁽¹⁾
Oil	$	30,157		$	43,736
Natural gas	13,769			18,729
Total oil and natural gas revenues	43,926			62,465
Realized gain on derivatives	7,063			18,504
Unrealized loss on derivatives	(6,839		)	(8,557		)
Total revenues	$	44,150		$	72,412
Net Production Volumes:⁽¹⁾
Oil (MBbl)⁽²⁾	1,044			1,009
Natural gas (Bcf)⁽³⁾	6.8			6.6
Total oil equivalent (MBOE)⁽⁴⁾	2,170			2,116
Average daily production (BOE/d)⁽⁵⁾	23,846			23,513
Average Sales Prices:
Oil, with realized derivatives (per Bbl)	$	34.12		$	57.68
Oil, without realized derivatives (per Bbl)	$	28.89		$	43.37
Natural gas, with realized derivatives (per Mcf)	$	2.27		$	3.43
Natural gas, without realized derivatives (per Mcf)	$	2.04		$	2.82

_________________


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


(2)	One thousand barrels of oil.


(3)	One billion cubic feet of natural gas.


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


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

Three Months Ended March 31, 2016 as Compared to Three Months Ended March 31, 2015

Oil and natural gas revenues. Our oil and natural gas revenues decreased $18.5 million to $43.9 million, or a decrease of 30%, for the three months ended March 31, 2016, as compared to $62.5 million for the three months ended March 31, 2015. Our oil revenues decreased $13.6 million, a decrease of 31%, to $30.2 million for the three months ended March 31, 2016, as compared to $43.7 million for the three months ended March 31, 2015. The decrease in oil revenues resulted from a significantly lower weighted average oil price realized for the three months ended March 31, 2016 of $28.89 per Bbl, as compared to $43.37 per Bbl realized for the three months ended March 31, 2015. This lower weighted average oil price was somewhat mitigated by the 3% increase in our oil production to 1.04 million Bbl of oil for the three months ended March 31, 2016, or about 11,473 Bbl of oil per day, as compared to just over 1.01 million Bbl of oil, or about 11,206 Bbl of oil per day, for the three months ended March 31, 2015. This increased oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin. Our natural gas revenues decreased by $5.0 million, or a decrease of 26%, to $13.8 million for the three months ended March 31, 2016, as compared to $18.7 million for the three months ended March 31, 2015. The decrease in natural gas revenues resulted from a lower weighted average natural gas price realized for the three months ended March 31, 2016 of $2.04 per Mcf, as compared to $2.82 per Mcf realized for the three months ended March 31, 2015. The lower weighted average natural gas price was partially mitigated by the 2% increase in our natural gas production to 6.8 Bcf for the three months ended March 31, 2016, as compared to 6.6 Bcf for the three months ended March 31, 2015. The increased natural gas production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin.

Realized gain on derivatives. Our realized gain on derivatives was $7.1 million for the three months ended March 31, 2016, as compared to a realized gain of $18.5 million for the three months ended March 31, 2015. We realized gains of $5.5

Table of Contents

million and $1.6 million from our oil and natural gas derivative contracts, respectively, for the three months ended March 31, 2016. For the three months ended March 31, 2015, we realized a net gain of $14.4 million, $3.6 million and $0.5 million attributable to our oil, natural gas and natural gas liquids (“NGL”) derivative contracts, respectively. The realized gains on our oil and natural gas derivative contracts during the respective periods were attributable to commodity prices being below the floor prices of the majority of our oil and natural gas costless collar contracts for the three months ended March 31, 2016 and 2015. The realized gain on our NGL derivative contracts during the three months ended March 31, 2015 resulted from NGL prices that were lower than the fixed prices of our NGL swap contracts; we had no open NGL derivative contracts in 2016. The average floor prices of our oil costless collar contracts were $45.12 per Bbl and $83.00 per Bbl as of March 31, 2016 and March 31, 2015, respectively. The average ceiling prices of our oil costless collar contracts were $68.32 per Bbl and $99.75 per Bbl as of March 31, 2016 and March 31, 2015, respectively. During the first quarter of 2016, our natural gas costless collar contracts had average floor and ceiling prices of $2.64 per MMBtu and $3.60 per MMBtu, respectively, as compared to $3.73 per MMBtu and $4.65 per MMBtu, respectively, during the first quarter of 2015. Our total oil and natural gas volumes hedged for the three months ended March 31, 2016 were 17% higher and 42% lower, respectively, than the total oil and natural gas volumes hedged for the same period in 2015.

Unrealized loss on derivatives. Our unrealized loss on derivatives was $6.8 million for the three months ended March 31, 2016, as compared to an unrealized loss of $8.6 million for the three months ended March 31, 2015. During the three months ended March 31, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased to $9.4 million from $16.3 million at December 31, 2015, resulting in an unrealized loss on derivatives of $6.8 million for the three months ended March 31, 2016. During the three months ended March 31, 2016, the net fair value of our open oil derivative contracts decreased by $7.7 million due primarily to the realized gains from oil derivative contracts settled during the three months ended March 31, 2016, and the net fair value of our open natural gas derivative contracts increased by $0.8 million due primarily to the decrease in natural gas prices during the three months ended March 31, 2016. During the three months ended March 31, 2015, the aggregate net fair value of our open oil, natural gas and NGL derivative contracts decreased to $47.0 million from $55.5 million for the year ended December 31, 2014, resulting in an unrealized loss on derivatives of $8.6 million for the three months ended March 31, 2015.

Table of Contents

Expenses

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



	Three Months Ended March 31,
(In thousands, except expenses per BOE)	2016			2015
Expenses:
Production taxes and marketing	$	7,902		$	7,049
Lease operating	15,489			13,046
Depletion, depreciation and amortization	28,923			46,470
Accretion of asset retirement obligations	264			112
Full-cost ceiling impairment	80,462			67,127
General and administrative	13,163			13,413
Total expenses	$	146,203		$	147,217
Operating loss	$	(102,053	)	$	(74,805	)
Other income (expense):
Net gain (loss) on asset sales and inventory impairment	$	1,065		$	(97	)
Interest expense	(7,197		)	(2,070		)
Interest and other income	518			384
Total other expense	$	(5,614	)	$	(1,783	)
Loss before income taxes	$	(107,667	)	$	(76,588	)
Total income tax (benefit) provision	—			(26,390		)
Net loss (income) attributable to non-controlling interest in subsidiaries	13			(36		)
Net loss attributable to Matador Resources Company shareholders	$	(107,654	)	$	(50,234	)
Expenses per BOE:
Production taxes and marketing	$	3.64		$	3.33
Lease operating	$	7.14		$	6.16
Depletion, depreciation and amortization	$	13.33		$	21.96
General and administrative	$	6.07		$	6.34

Three Months Ended March 31, 2016 as Compared to Three Months Ended March 31, 2015

Production taxes and marketing. Our production taxes and marketing expenses increased by $0.9 million to $7.9 million, or an increase of 12%, for the three months ended March 31, 2016, as compared to $7.0 million for the three months ended March 31, 2015. On a unit-of-production basis our production taxes and marketing expenses increased by 9% to $3.64 per BOE for the three months ended March 31, 2016, as compared to $3.33 per BOE for the three months ended March 31, 2015. The increase in production taxes and marketing expenses was primarily attributable to higher natural gas marketing and processing expenses of $5.7 million for the three months ended March 31, 2016, as compared to natural gas marketing and processing expenses of $4.4 million for the three months ended March 31, 2015. This increase of $1.3 million was due to the increase in natural gas production in the Delaware Basin as a percentage of our total natural gas production for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015. Natural gas marketing and processing expenses are higher in the Delaware Basin, as compared to the Eagle Ford shale, as the natural gas gathering and processing infrastructure has not yet caught up with the demand for these services due to the increased drilling activity in the Delaware Basin over the last few years. We anticipate that we will incur lower marketing and processing expenses for the natural gas produced in Eddy County, New Mexico once the cryogenic natural gas processing plant we are constructing and installing in the Rustler Breaks prospect area is completed and operational. On an absolute basis, our production taxes decreased by $0.4 million to $2.2 million for the three months ended March 31, 2016, as compared to $2.7 million for the three months ended March 31, 2015, primarily due to the 30% decrease in oil and natural gas revenues in the first quarter of 2016 as compared to the first quarter of 2015.

Lease operating expenses. Our lease operating expenses increased by $2.4 million to $15.5 million, or an increase of 19%, for the three months ended March 31, 2016, as compared to $13.0 million for the three months ended March 31, 2015. Our lease operating expenses per unit of production increased 16% to $7.14 per BOE for the three months ended March 31, 2016, as compared to $6.16 per BOE for the three months ended March 31, 2015. Our total oil equivalent production increased 3% to approximately 2.17 million BOE for the three months ended March 31, 2016 from approximately 2.12 million BOE for the three months ended March 31, 2015. Oil production was 48% of total production by volume for the three months ended

Table of Contents

March 31, 2016, as compared to 48% of total production by volume for the three months ended March 31, 2015. The increase in lease operating expenses on both an absolute and per unit of production basis is primarily attributable to (i) inclement weather affecting operations in the Delaware Basin and the Haynesville shale and Cotton Valley plays, (ii) increased field supervisory costs associated with our expanding Delaware Basin operations, (iii) higher-than-anticipated salt water disposal costs in the Rustler Breaks prospect area early in the first quarter and (iv) costs associated with unanticipated maintenance and mechanical issues on several of our Eagle Ford properties.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased by $17.5 million to $28.9 million, or a decrease of 38%, for the three months ended March 31, 2016, as compared to $46.5 million for the three months ended March 31, 2015. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased to $13.33 per BOE for the three months ended March 31, 2016, or a decrease of 39%, from $21.96 per BOE for the three months ended March 31, 2015. The decrease in the depletion, depreciation and amortization expenses was primarily attributable to the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015, as well as the 14% increase in our total estimated proved oil and natural gas reserves between the two periods.

Full-cost ceiling impairment. At March 31, 2016, the net capitalized costs of our oil and natural gas properties exceeded the full-cost ceiling by $80.5 million. As a result, we recorded an impairment charge of $80.5 million to the net capitalized costs of our oil and natural gas properties. This full-cost ceiling impairment is reflected in our interim unaudited condensed consolidated statement of operations for the three months ended March 31, 2016. We also recorded an impairment charge of $67.1 million to the net capitalized costs of our oil and natural gas properties for the three months ended March 31, 2015.

In determining the full-cost ceiling impairment at March 31, 2016, we estimated the PV-10 of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2016 as required under the guidelines established by the SEC, which were $42.77 per Bbl and $2.40 per MMBtu, respectively. If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2016 had been $39.38 per Bbl and $2.26 per MMBtu, respectively, while all other factors remained constant, our full-cost ceiling would have been reduced by an additional $111.9 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the twelve month period July 2015 through June 2016, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 11 months ended May 2016, with the price for May 2016 being held constant for June 2016. This pro forma increase in the excess of our net capitalized costs above the full-cost ceiling is attributable to a pro forma reduction of $111.9 million in the PV-10 of our total proved oil and natural gas reserves, including a pro forma decrease in our estimated total proved reserves to 88.6 million BOE, or a reduction of approximately 2%, from our reported estimated proved reserves of 90.2 million BOE at March 31, 2016, primarily attributable to certain proved undeveloped locations that would no longer be classified as proved undeveloped reserves using the pro forma prices. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. The impact of prices is only one of several variables in the estimation of our proved reserves and full-cost ceiling and other factors could have a significant impact on our future proved reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

General and administrative. Our general and administrative expenses decreased by $0.3 million to $13.2 million, or a decrease of 2%, for the three months ended March 31, 2016, as compared to $13.4 million for the three months ended March 31, 2015. During the first quarter of 2015, we incurred one-time transaction costs of approximately $2.2 million in connection with the merger of our wholly-owned subsidiary with Harvey E. Yates Company (the “HEYCO Merger”) in late February 2015. In the first quarter of 2016, these prior year transaction costs were substantially offset by increased payroll expenses associated with additional employees joining the Company between the respective periods, including the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO Merger. General and administrative expenses also included non-cash stock-based compensation expense of $2.2 million and $2.3 million for the three months ended March 31, 2016 and 2015, respectively. The decrease in our general and administrative expenses on a unit-of-production basis to $6.07 per BOE for the three months ended March 31, 2016, as compared to $6.34 per BOE for the three months ended March 31, 2015, was also attributable to the 2% increase in total oil equivalent production between the respective periods.

Net gain (loss) on asset sales and inventory impairment. For the three months ended March 31, 2016, we recognized $1.1 million of the deferred gain on the sale of certain natural gas gathering and processing assets in Loving County, Texas that

Table of Contents

occurred in the fourth quarter of 2015. For the three months ended March 31, 2015, we recorded a loss on the sale of inventory of $97,000.

Interest expense. For the three months ended March 31, 2016, we incurred total interest expense of $7.6 million. We capitalized $0.4 million of our interest expense on certain qualifying projects for the three months ended March 31, 2016 and expensed the remaining $7.2 million. For the three months ended March 31, 2015, we incurred total interest expense of $3.0 million. We capitalized $1.0 million of our interest expense on certain qualifying projects for the three months ended March 31, 2015 and expensed the remaining $2.1 million to operations. The increase in total interest expense is attributable to an increase in the average effective interest rate between comparable periods due to the issuance of our 6.875% senior notes due 2023 (the “Notes”) in April 2015. In late April 2015, we used a portion of the net proceeds from the issuance of the Notes and our April 2015 equity offering to repay all outstanding borrowings under our Credit Agreement, which had an effective interest rate of 2.9% for the three months ended March 31, 2015. At March 31, 2016, we had no borrowings outstanding and $0.6 million in letters of credit outstanding under our Credit Agreement and $400.0 million in outstanding Notes.

Total income tax provision (benefit). At March 31, 2016, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax assets generated by the full-cost ceiling impairment charges recorded; as a result, we established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015. Total income tax expense for the three months ended March 31, 2015 differed from amounts computed by applying the U.S. federal statutory tax rate to loss before income taxes due primarily to the impact of permanent differences between book and taxable income.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during the remainder of 2016 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for related midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditure requirements through the remainder of 2016 through a combination of cash on hand, the proceeds from our recent 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, potential joint ventures, the sale of midstream or other assets or acreage and potential issuances of equity, debt or convertible securities, none of which may be available. 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.

During the three months ended March 31, 2016, we completed a public offering of 7,500,000 shares of common stock. After deducting offering costs totaling approximately $0.8 million, we received net proceeds of approximately $141.5 million. At March 31, 2016, we had cash totaling $118.3 million and the borrowing base under our Credit Agreement was $375.0 million. At both March 31, 2016 and May 5, 2016, we had no borrowings outstanding and $0.6 million in outstanding letters of credit pursuant to our Credit Agreement and $400.0 million of outstanding Notes. On May 3, 2016, the borrowing base under our Credit Agreement was reduced to $300.0 million from $375.0 million based on our lenders’ review of our proved oil and natural gas reserves at December 31, 2015 using commodity price estimates prescribed by the lenders. The borrowing base reduction was primarily attributable to the significant decline in oil and natural gas prices experienced since July 2014. All other provisions of our Credit Agreement remain unchanged.

As of May 5, 2016, we anticipated investing approximately $325.0 million in capital for acquisition, exploration and development activities in 2016 as follows:



	Amount (in millions)
Exploration, development drilling and completion costs, including production facilities and infrastructure	$	260.0
Midstream activities	40.0
Leasehold acquisition and 2-D and 3-D seismic data	25.0
Total	$	325.0

Our 2016 capital expenditures may be adjusted as business conditions warrant, as evidenced by the substantial reduction in our 2016 capital expenditure budget, as compared to our 2015 capital spending, in response to the sharp decline in oil and natural gas prices since mid-2014. While we have budgeted $325.0 million in capital expenditures for 2016, the amount, timing and allocation of our capital expenditures is largely discretionary and within our control. Our 2016 capital expenditure budget includes approximately $260.0 million for drilling, completions, facilities and infrastructure, $40.0 million principally for the completion of new midstream facilities in the Delaware Basin to support our operations there and $25.0 million for land and seismic data, principally in the Delaware Basin.

Development of our Delaware Basin assets will be the primary driver of our projected growth in 2016. Approximately $315.0 million, or 97%, of our estimated 2016 capital expenditures will be allocated to the further delineation and development

Table of Contents

of our growing leasehold position in the Delaware Basin. Our 2016 Delaware Basin drilling program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of the Ranger and Arrowhead prospect areas. The $40.0 million in midstream capital expenditures is expected to primarily fund completion of the construction and installation of a cryogenic natural gas processing plant with approximately 60 MMcf per day of inlet capacity and a natural gas gathering system in the Rustler Breaks prospect area in Eddy County, New Mexico (the “Eddy County System”). This plant is expected to be operational by the third quarter of 2016.

We do not plan to drill any operated Eagle Ford shale wells in South Texas or Haynesville shale natural gas wells in Northwest Louisiana during 2016. Approximately $5.6 million, or 2%, of our 2016 estimated capital expenditures will be allocated to the Eagle Ford shale to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired, and approximately $4.4 million, or just over 1%, of our 2016 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells. Approximately 92% of our Eagle Ford acreage and essentially all of our Haynesville and Cotton Valley acreage was either held by production at December 31, 2015 or not burdened by lease expirations before 2017.

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 of our midstream activities, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, as oil and natural gas prices have done since mid-2014, 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 in 2016 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 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 2016 and the hedges we currently have in place. We use commodity derivative financial instruments 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. At May 5, 2016, we had approximately 50% of our anticipated oil production and approximately 44% of our anticipated natural gas production hedged for the remainder of 2016. See Note 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at March 31, 2016.

Our unaudited cash flows for the three months ended March 31, 2016 and 2015 are presented below:



	Three Months Ended March 31,
(In thousands)	2016			2015
Net cash provided by operating activities	$	18,358		$	93,346
Net cash used in investing activities	(57,932		)	(166,092		)
Net cash provided by financing activities	141,171			70,400
Net change in cash	$	101,597		$	(2,346	)
Adjusted EBITDA⁽¹⁾	$	17,209		$	50,146

__________________


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

Cash Flows Provided by Operating Activities

Net cash provided by operating activities decreased by $75.0 million to $18.4 million for the three months ended March 31, 2016, as compared to net cash provided by operating activities of $93.3 million for the three months ended March 31, 2015. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased by $37.8 million to $10.3 million for the three months ended March 31, 2016 from $48.1 million for the three months ended March 31, 2015. This decrease is primarily attributable to the 30% decrease in our oil and natural gas revenues between the respective periods.

Table of Contents

Changes in our operating assets and liabilities between March 31, 2015 and March 31, 2016 resulted in a net decrease of $37.2 million in net cash provided by operating activities for the three months ended March 31, 2016.

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

Cash Flows Used in Investing Activities

Net cash used in investing activities decreased by $108.2 million to $57.9 million for the three months ended March 31, 2016 from $166.1 million for the three months ended March 31, 2015. This decrease in net cash used in investing activities for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015, is primarily attributable to the following factors: (i) a decrease of $53.1 million in oil and natural gas properties capital expenditures due to our reduced 2016 capital expenditure budget, (ii) a decrease in cash used in business combinations of $24.0 million and (iii) a decrease in restricted cash of $44.2 million primarily attributable to the return of cash from the escrow account established to facilitate potential like-kind exchange transactions associated with the sale of certain midstream assets in Loving County, Texas in the fourth quarter of 2015. This decrease was partially offset by the increase in cash used primarily for our midstream investments of $13.2 million, including for the construction and installation of the Eddy County System. Cash used for oil and natural gas properties capital expenditures for the three months ended March 31, 2016 was primarily attributable to our operated drilling and completion activities in the Delaware Basin. A small portion of our capital expenditures for the three months ended March 31, 2016 was directed to our participation in non-operated wells, primarily in the Delaware Basin and the Haynesville shale.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities increased by $70.8 million to $141.2 million for the three months ended March 31, 2016 from $70.4 million for the three months ended March 31, 2015. The net cash provided by financing activities for the three months ended March 31, 2016 was attributable to the net proceeds from our equity offering of $141.7 million ($141.5 million including accrued cost to issue equity), which was slightly offset by $0.6 million in taxes paid related to net share settlements of stock-based compensation. The net cash provided by financing activities for the three months ended March 31, 2015 was primarily attributable to incremental borrowings under our Credit Agreement of $70.0 million and capital contributions from non-controlling interest owners in a less-than-wholly-owned subsidiary of $0.5 million.

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

Non-GAAP Financial Measures

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

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

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an 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.

Table of Contents

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



	Three Months Ended March 31,
(In thousands)	2016			2015
Unaudited Adjusted EBITDA Reconciliation to Net Loss:
Net loss attributable to Matador Resources Company shareholders	$	(107,654	)	$	(50,234	)
Interest expense	7,197			2,070
Total income tax (benefit) provision	—			(26,390		)
Depletion, depreciation and amortization	28,923			46,470
Accretion of asset retirement obligations	264			112
Full-cost ceiling impairment	80,462			67,127
Unrealized loss on derivatives	6,839			8,557
Stock-based compensation expense	2,243			2,337
Net (gain) loss on asset sales and inventory impairment	(1,065		)	97
Adjusted EBITDA	$	17,209		$	50,146



	Three Months Ended March 31,
(In thousands)	2016			2015
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	18,358		$	93,346
Net change in operating assets and liabilities	(8,059		)	(45,234		)
Interest expense, net of non-cash portion	6,897			2,070
Net loss (income) attributable to non-controlling interest in subsidiary	13			(36		)
Adjusted EBITDA	$	17,209		$	50,146

Our Adjusted EBITDA decreased by $32.9 million to $17.2 million, or a decrease of 66%, for the three months ended March 31, 2016, as compared to $50.1 million for the three months ended March 31, 2015. This decrease in our Adjusted EBITDA is primarily attributable to the decrease in our oil and natural gas revenues resulting from lower commodity prices for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, 2016, 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 and fractionation commitments, (v) agreements to construct facilities and (vi) 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, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “Obligations and Commitments” below and Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

Table of Contents

Obligations and Commitments

We had the following material contractual obligations and commitments at March 31, 2016:



	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⁾	$	571	$	571	$	—	$	—	$	—
Senior unsecured notes⁽²⁾	400,000		—		—		—		400,000
Office leases	26,837		2,390		4,945		5,172		14,330
Non-operated drilling commitments⁽³⁾	4,743		4,743		—		—		—
Drilling rig contracts⁽⁴⁾	43,228		22,950		20,278		—		—
Asset retirement obligations	17,225		48		1,666		4,118		11,393
Gas processing and transportation agreements⁽⁵⁾	11,469		7,157		4,312		—		—
Gas plant engineering, procurement, construction and installation contract ⁽⁶⁾	8,602		8,602		—		—		—
Total contractual cash obligations	$	512,675	$	46,461	$	31,201	$	9,290	$	425,723

__________________


(1)	At March 31, 2016, we had no borrowings outstanding under our Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020.


(2)	These amounts represent principal maturities only.

(3)

At March 31, 2016, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and several of these wells were in progress at March 31, 2016. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of $4.7 million at March 31, 2016, which we expect to incur within the next few months.

(4)

We do not own or operate our own drilling rigs, but instead enter into contracts with third parties for such rigs. These contracts establish daily rates for the drilling rigs and the term of our commitments for the drilling services to be provided, which have typically been for one year or less, although we have entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were until recently experiencing heavy demand for drilling rigs. Should we elect to terminate a contract and if the drilling contractor were unable to secure work for the contracted drilling rig or if the drilling contractor were unable to secure work for the contracted drilling rig at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under our drilling rig contracts were $43.2 million at March 31, 2016.

(5)

Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. The undiscounted minimum commitments under this agreement totaled approximately $2.5 million at March 31, 2016. Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. The undiscounted minimum commitments under this agreement total approximately $212.6 million at March 31, 2016; however, at the end of each year of the agreement, we can elect to have the previous year’s actual gathering and processing volumes be the new minimum commitment for each of the remaining years under the contract. As such, we have the ability to unilaterally reduce the gathering and processing commitment if our production in the Loving County area is less than our currently projected production. In addition, if we elect to reduce the gathering and processing commitment in any year, we have the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. If we do not meet the volume commitment for gathering and processing at the facility in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. If we did not use any of our commitment and elected to reduce our future years’ commitment to zero, the deficiency payment required to be paid under the contract would be approximately $8.9 million at March 31, 2016 and no further deficiency payments would be required in future years.

(6)

We entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in the Rustler Breaks prospect area in Eddy County, New Mexico in 2015. This plant is expected to process a portion of our natural gas produced from certain of our wells in the Delaware Basin, as well as third-party natural gas. The plant is scheduled to be completed and placed in service in the third quarter of 2016.

General Outlook and Trends

For the three months ended March 31, 2016, oil prices ranged from a low of approximately $26.21 per Bbl in mid-February to a high of approximately $41.45 per Bbl in late March, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized an average oil price of $28.89 per Bbl ($34.12 per Bbl including realized gains from oil derivatives) for our oil production for the three months ended March 31, 2016, as compared to $43.37 per Bbl ($57.68 per Bbl including realized gains from oil derivatives) for the three months ended March 31, 2015. Subsequent to March 31, 2016, oil prices have increased and, at May 5, 2016, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date closed at $44.32 per Bbl, as compared to $60.40 per Bbl at May 5, 2015.

Table of Contents

For the three months ended March 31, 2016, natural gas prices ranged from a high of $2.47 per MMBtu in early January to a low of $1.64 per MMBtu in early March, 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 $2.04 per Mcf ($2.27 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the three months ended March 31, 2016, as compared to $2.82 per Mcf ($3.43 per Mcf including aggregate realized gains from natural gas and NGL derivatives) for the three months ended March 31, 2015. Because we report our production volumes in two streams, oil and natural gas, including dry and liquids-rich natural gas, revenues associated with extracted natural gas liquids are included with our natural gas revenues, which has the effect of increasing the weighted average natural gas price realized on a per Mcf basis. Since March 31, 2016, natural gas prices have increased somewhat but have remained depressed, and at May 5, 2016, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.08 per MMBtu, as compared to $2.78 per MMBtu at May 5, 2015.

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 when, or 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. Additionally, as our oil and natural gas derivative financial instruments that were entered into prior to the decline in commodity prices in late 2014 and early 2015 expire, we have begun to replace them with derivative instruments with lower floor and ceiling prices. As a result, we expect our realized gains from derivatives to be less for the remainder of 2016, as compared to comparable periods in 2015, especially from our oil derivative contracts.

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 additional 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 availability under our Credit Agreement.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, 2015, which are disclosed in the Annual Report.

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

We 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 time, providing downside price protection.

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities,

Table of Contents

(ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. At March 31, 2016, Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal) and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have evaluated the credit standing of the counterparties in determining the fair value of our derivative financial instruments. See Note 8 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments at March 31, 2016. Such information is incorporated herein by reference.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2016 to ensure that (i) information required to be disclosed in the reports the Company 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 its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2016, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

Part II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

During the quarter ended March 31, 2016, 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
January 1, 2016 to January 31, 2016	—	$	—	—	—
February 1, 2016 to February 29, 2016	—	—		—	—
March 1, 2016 to March 31, 2016	21,931	20.34		—	—
Total	21,931	$	20.34	—	—

_________________

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

Item 6. Exhibits

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

Table of Contents

SIGNATURES

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



		MATADOR RESOURCES COMPANY

Date: May 6, 2016	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman and Chief Executive Officer



Date: May 6, 2016	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President and Chief Financial Officer

Table of Contents

EXHIBIT INDEX



Exhibit Number		Description
2.1		Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group, Inc., Matador Resources Company and MRC Delaware Resources, LLC (filed herewith).*

3.1		Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011).

3.2		Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012).

3.3		Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).

3.4		Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 25, 2016).

3.5		Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015).

23.1		Consent of Netherland, Sewell & Associates, Inc. (filed herewith).

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

99.1		Audit report of Netherland, Sewell & Associates, Inc. (filed herewith).

101		The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets - Unaudited, (ii) the Condensed Consolidated Statements of Operations - Unaudited, (iii) the Condensed Consolidated Statement of Changes in Shareholders’ Equity - Unaudited, (iv) the Condensed Consolidated Statements of Cash Flows - Unaudited and (v) the Notes to Condensed Consolidated Financial Statements - Unaudited (submitted electronically herewith).

*Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.