8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________

FORM 8-K

_________________________________

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of Earliest Event Reported) March 9, 2017

_________________________________

Matador Resources Company

(Exact name of registrant as specified in its charter)

_________________________________

Texas	001-35410	27-4662601
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

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

Registrant’s telephone number, including area code: (972) 371-5200

Not Applicable

(Former name or former address, if changed since last report)

_________________________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

As previously reported, on December 9, 2016, Matador Resources Company (“Matador”) issued $175,000,000 in aggregate principal amount of Matador’s 6.875% Senior Notes due 2023 (the “Additional Notes”). The Additional Notes were issued under the Indenture (as defined below) as additional notes to Matador’s $400,000,000 in aggregate principal amount of 6.875% Senior Notes due 2023 (collectively with the Additional Notes, the “Notes”). On February 17, 2017, in connection with the formation of San Mateo Midstream, LLC (“San Mateo”), a joint venture with FP MMP Holdings LLC, a subsidiary of Five Point Capital Partners LLC, Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”) with Wells Fargo Bank, National Association, as trustee (the “Trustee”), which supplements the Indenture, dated as of April 14, 2015 (as supplemented and amended, the “Indenture”), among Matador, the guarantors named therein and the Trustee, which governs the terms of the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes under the Indenture and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes under the Indenture. The guarantors of the Notes under the Indenture, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Existing Guarantor Subsidiaries.” San Mateo and its subsidiaries are not guarantors of the Notes.

In connection with the issuance of the Additional Notes, Matador agreed to file a registration statement on Form S-4, as may be amended (the “Registration Statement”), with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the Additional Notes for substantially identical notes that are registered under the Securities Act of 1933, as amended. In connection with the Registration Statement to be filed by Matador and the Existing Guarantor Subsidiaries, this Current Report on Form 8-K (this “Current Report”) is being filed to include an update to Matador’s audited financial statements as of December 31, 2016 and 2015 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2016 (the “Updated Financial Statements”), solely to include Note 19, “Guarantor Financial Information,” providing the condensed consolidating financial information as required by Rule 3-10(f) of Regulation S-X regarding the Existing Guarantor Subsidiaries and Matador’s non-guarantor subsidiaries.

The Updated Financial Statements are set forth as Exhibit 99.1 to this Current Report and will be incorporated by reference in the Registration Statement. Other than the addition of Note 19, “Guarantor Financial Information,” the information in the Updated Financial Statements remains unchanged and has not otherwise been updated for activities or events occurring after the date this information was originally presented in Matador’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Form 10-K”). The information included in this Current Report should be read in conjunction with the Form 10-K and any other filings Matador has made, or will make prior to the effectiveness of the Registration Statement, with the SEC.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit No.	Description of Exhibit
23.1	Consent of KPMG LLP.
99.1	Financial statements of Matador Resources Company and subsidiaries as of December 31, 2016 and 2015, and for each of the years in the three-year period ended December 31, 2016, as updated solely to include Note 19, “Guarantor Financial Information.”
101	The following financial information from Exhibit 99.1 to this Current Report on Form 8-K, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).

SIGNATURE

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 hereunto duly authorized.

	MATADOR RESOURCES COMPANY
Date: March 9, 2017	By:	/s/ Craig N. Adams
	Name:	Craig N. Adams
	Title:	Executive Vice President

Exhibit Index

Exhibit No.	Description of Exhibit
23.1	Consent of KPMG LLP.
99.1	Financial statements of Matador Resources Company and subsidiaries as of December 31, 2016 and 2015, and for each of the years in the three-year period ended December 31, 2016, as updated solely to include Note 19, “Guarantor Financial Information.”
101	The following financial information from Exhibit 99.1 to this Current Report on Form 8-K, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Matador Resources Company:

We consent to the incorporation by reference in the registration statements (File No. 333-187808 and 333-196178) on Form S-3, and (File No. 333-180641 and 333-204868) on Form S-8 of Matador Resources Company of our report dated March 1, 2017, except as to Note 19, which is as of March 9, 2017, with respect to the consolidated balance sheets of Matador Resources Company as of December 31, 2016 and 2015, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016, which report appears in the Current Report on Form 8-K of Matador Resources Company filed March 9, 2017.

/s/ KPMG LLP

Dallas, Texas

March 9, 2017

EX-99.1

Exhibit 99.1

Matador Resources Company and Subsidiaries

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

Contents

Report of Independent Registered Public Accounting Firm	2
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2016 and 2015	3
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	4
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014	5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	6
Notes to Consolidated Financial Statements	7
Unaudited Supplementary Information	43

1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Matador Resources Company:

We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (collectively the “Company”) as of December 31, 2016 and 2015 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2017 (not included herein) expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 1, 2017, except for Note 19,

as to which the date is March 9, 2017

2

Matador Resources Company and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share data)

	December 31,
	2016			2015
ASSETS
Current assets
Cash	$	212,884		$	16,732
Restricted cash	1,258			44,357
Accounts receivable
Oil and natural gas revenues	34,154			16,616
Joint interest billings	19,347			16,999
Other	5,167			10,794
Derivative instruments	—			16,284
Lease and well equipment inventory	3,045			2,022
Prepaid expenses and other assets	3,327			3,203
Total current assets	279,182			127,007
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,408,305			2,122,174
Unproved and unevaluated	479,736			387,504
Other property and equipment	160,795			86,387
Less accumulated depletion, depreciation and amortization	(1,864,311		)	(1,583,659		)
Net property and equipment	1,184,525			1,012,406
Other assets	958			1,448
Total assets	$	1,464,665		$	1,140,861
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	4,674		$	10,966
Accrued liabilities	101,460			92,369
Royalties payable	23,988			16,493
Amounts due to affiliates	8,651			5,670
Derivative instruments	24,203			—
Advances from joint interest owners	1,700			700
Deferred gain on plant sale	—			4,830
Amounts due to joint ventures	4,251			2,793
Income taxes payable	—			2,848
Other current liabilities	578			161
Total current liabilities	169,505			136,830
Long-term liabilities
Senior unsecured notes payable	573,924			391,254
Asset retirement obligations	19,725			15,166
Derivative instruments	751			—
Amounts due to joint ventures	1,771			3,956
Deferred gain on plant sale	—			102,506
Other long-term liabilities	7,544			2,190
Total long-term liabilities	603,715			515,072
Commitments and contingencies (Note 13)
Shareholders’ equity
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995			856
Additional paid-in capital	1,325,481			1,026,077
Accumulated deficit	(636,351		)	(538,930		)
Total Matador Resources Company shareholders’ equity	690,125			488,003
Non-controlling interest in subsidiaries	1,320			956
Total shareholders’ equity	691,445			488,959
Total liabilities and shareholders’ equity	$	1,464,665		$	1,140,861

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

3

Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	For the Years Ended December 31,
	2016			2015			2014
Revenues
Oil and natural gas revenues	$	291,156		$	278,340		$	367,712
Third-party midstream services revenues	5,218			1,864			1,213
Realized gain on derivatives	9,286			77,094			5,022
Unrealized (loss) gain on derivatives	(41,238		)	(39,265		)	58,302
Total revenues	264,422			318,033			432,249
Expenses
Production taxes, transportation and processing	43,046			35,650			33,172
Lease operating	56,202			54,704			49,945
Plant and other midstream services operating	5,389			3,489			1,408
Depletion, depreciation and amortization	122,048			178,847			134,737
Accretion of asset retirement obligations	1,182			734			504
Full-cost ceiling impairment	158,633			801,166			—
General and administrative	55,089			50,105			32,152
Total expenses	441,589			1,124,695			251,918
Operating (loss) income	(177,167		)	(806,662		)	180,331
Other income (expense)
Net gain on asset sales and inventory impairment	107,277			908			—
Interest expense	(28,199		)	(21,754		)	(5,334		)
Other (expense) income	(4		)	616			132
Total other income (expense)	79,074			(20,230		)	(5,202		)
(Loss) income before income taxes	(98,093		)	(826,892		)	175,129
Income tax provision (benefit)
Current	(1,036		)	2,959			133
Deferred	—			(150,327		)	64,242
Total income tax (benefit) provision	(1,036		)	(147,368		)	64,375
Net (loss) income	(97,057		)	(679,524		)	110,754
Net (income) loss attributable to non-controlling interest in subsidiaries	(364		)	(261		)	17
Net (loss) income attributable to Matador Resources Company shareholders	$	(97,421	)	$	(679,785	)	$	110,771
Earnings (loss) per common share
Basic	$	(1.07	)	$	(8.34	)	$	1.58
Diluted	$	(1.07	)	$	(8.34	)	$	1.56
Weighted average common shares outstanding
Basic	91,273			81,537			70,229
Diluted	91,273			81,537			70,906

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

4

Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(In thousands)

For the Years Ended December 31, 2016, 2015 and 2014

																						Total shareholders’ equity attributable to Matador Resources Company
											Additional paid-in capital			Retained earnings (deficit)			Treasury Stock								Non-controlling interest in subsidiaries			Total shareholders’ equity
	Common Stock					Preferred Stock
	Shares		Amount			Shares		Amount									Shares		Amount
Balance at January 1, 2014	66,959		$	670		—		$	—		$	548,935		$	30,084		1,306		$	(10,765	)	$	568,924		$	—		$	568,924
Issuance of common stock	7,500		75			—		—			181,800			—			—		—			181,875			—			181,875
Cost to issue equity	—		—			—		—			(590		)	—			—		—			(590		)	—			(590		)
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	30		—			—		—			16			—			—		—			16			—			16
Stock options expense related to equity-based awards	—		—			—		—			2,279			—			—		—			2,279			—			2,279
Stock options exercised, net of options forfeited in net share settlements	8		—			—		—			43			—			—		—			43			—			43
Liability-based stock option awards settled	—		—			—		—			84			—			—		—			84			—			84
Restricted stock issued	212		2			—		—			(2		)	—			—		—			—			—			—
Restricted stock forfeited	—		—			—		—			(17		)	—			60		—			(17		)	—			(17		)
Restricted stock and restricted stock units expense	—		—			—		—			3,023			—			—		—			3,023			—			3,023
Cancellation of treasury stock	(1,335	)	(13		)	—		—			(10,752		)	—			(1,335	)	10,765			—			—			—
Capital contributed to less-than-wholly-owned subsidiaries	—		—			—		—			—			—			—		—			—			150			150
Current period net income (loss)	—		—			—		—			—			110,771			—		—			110,771			(17		)	110,754
Balance at December 31, 2014	73,374		734			—		—			724,819			140,855			31		—			866,408			133			866,541
Issuance of common stock	10,329		104			—		—			260,148			—			—		—			260,252			—			260,252
Issuance of preferred stock	—		—			150		1			32,489			—			—		—			32,490			—			32,490
Cost to issue equity	—		—			—		—			(1,151		)	—			—		—			(1,151		)	—			(1,151		)
Conversion of preferred stock to common stock	1,500		15			(150	)	(1		)	(14		)	—			—		—			—			—			—
Stock-based compensation expense related to equity-based awards	—		—			—		—			9,333			—			—		—			9,333			—			9,333
Stock options exercised, net of options forfeited in net share settlements	25		—			—		—			10			—			—		—			10			—			10
Liability-based stock option awards settled	25		—			—		—			446			—			—		—			446			—			446
Restricted stock issued	429		4			—		—			(4		)	—			—		—			—			—			—
Restricted stock forfeited	—		—			—		—			—			—			138		—			—			—			—
Vesting of restricted stock units	52		1			—		—			(1		)	—			—		—			—			—			—
Cancellation of treasury stock	(167	)	(2		)	—		—			2			—			(167	)	—			—			—			—
Capital contributed from less-than-wholly-owned subsidiaries	—		—			—		—			—			—			—		—			—			562			562
Current period net (loss) income	—		—			—		—			—			(679,785		)	—		—			(679,785		)	261			(679,524		)
Balance at December 31, 2015	85,567		856			—		—			1,026,077			(538,930		)	2		—			488,003			956			488,959
Issuance of common stock pursuant to public offerings	13,500		135			—		—			288,375			—			—		—			288,510			—			288,510
Issuance of common stock pursuant to employee stock compensation plan	471		4			—		—			(4		)	—			—		—			—			—			—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	51		1			—		—			(1		)	—			—		—			—			—			—
Cost to issue equity	—		—			—		—			(1,190		)	—			—		—			(1,190		)	—			(1,190		)
Stock-based compensation expense related to equity-based awards	—		—			—		—			11,958			—			—		—			11,958			—			11,958
Stock options exercised, net of options forfeited in net share settlements	36		—			—		—			10			—			—		—			10			—			10
Liability-based stock option awards settled	10		—			—		—			255			—			—		—			255			—			255
Restricted stock forfeited	—		—			—		—			—			—			120		—			—			—			—
Cancellation of treasury stock	(116	)	(1		)	—		—			1			—			(116	)	—			—			—			—
Current period net (loss) income	—		—			—		—			—			(97,421		)	—		—			(97,421		)	364			(97,057		)
Balance at December 31, 2016	99,519		$	995		—		$	—		$	1,325,481		$	(636,351	)	6		$	—		$	690,125		$	1,320		$	691,445

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

5

Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	For the Years Ended December 31,
	2016			2015			2014
Operating activities
Net (loss) income	$	(97,057	)	$	(679,524	)	$	110,754
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	41,238			39,265			(58,302		)
Depletion, depreciation and amortization	122,048			178,847			134,737
Accretion of asset retirement obligations	1,182			734			504
Full-cost ceiling impairment	158,633			801,166			—
Stock-based compensation expense	12,362			9,450			5,524
Deferred income tax (benefit) provision	—			(150,327		)	64,242
Amortization of debt issuance cost	1,148			852			—
Net gain on asset sales and inventory impairment	(107,277		)	(908		)	—
Changes in operating assets and liabilities
Accounts receivable	(14,259		)	3,633			(13,318		)
Lease and well equipment inventory	(700		)	(180		)	(211		)
Prepaid expenses	(124		)	(544		)	(783		)
Other assets	490			(552		)	1,212
Accounts payable, accrued liabilities and other current liabilities	6,611			1,375			607
Royalties payable	7,495			1,654			6,663
Advances from joint interest owners	1,000			700			—
Income taxes payable	(2,848		)	2,405			39
Other long-term liabilities	4,144			489			(187		)
Net cash provided by operating activities	134,086			208,535			251,481
Investing activities
Proceeds from sale of assets	5,173			139,836			79
Oil and natural gas properties capital expenditures	(379,067		)	(432,715		)	(560,849		)
Expenditures for other property and equipment	(74,845		)	(64,499		)	(9,152		)
Business combination, net of cash acquired	—			(24,028		)	—
Restricted cash	43,098			(43,098		)	—
Restricted cash in less-than-wholly-owned subsidiaries	1			(650		)	(609		)
Net cash used in investing activities	(405,640		)	(425,154		)	(570,531		)
Financing activities
Repayments of borrowings	(120,000		)	(476,982		)	(180,000		)
Borrowings under Credit Agreement	120,000			125,000			320,000
Proceeds from issuance of common stock	288,510			188,720			181,875
Proceeds from issuance of senior unsecured notes	184,625			400,000			—
Cost to issue equity	(847		)	(1,158		)	(590		)
Cost to issue senior unsecured notes	(2,734		)	(9,598		)	—
Proceeds from stock options exercised	100			10			43
Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries	—			562			150
Taxes paid related to net share settlement of stock-based compensation	(1,948		)	(1,610		)	(308		)
Net cash provided by financing activities	467,706			224,944			321,170
Increase in cash	196,152			8,325			2,120
Cash at beginning of year	16,732			8,407			6,287
Cash at end of year	$	212,884		$	16,732		$	8,407

Supplemental disclosures of cash flow information (Note 14)

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

6

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

NOTE 1 — NATURE OF OPERATIONS

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

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company 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. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting at December 31, 2016. As a result, $1.8 million and $1.2 million for the years ended December 31, 2015 and 2014, respectively, were reclassified from other income to third-party midstream services revenues. In addition, $3.5 million and $1.4 million related to midstream operating costs for the years ended December 31, 2015 and 2014, respectively, were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Change in Accounting Principles

During the second quarter of 2016, the Company adopted Accounting Standards Update (“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, requiring either retrospective, modified retrospective or prospective transition. The amended guidance also requires an entity to record excess tax benefits and deficiencies in the income statement. The adoption of this ASU had no impact on any period presented for (i) the Company’s financial position or statements of operations, as the Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of cash flows, as the Company has historically accounted for taxes paid for net share settlement as a financing activity as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of this ASU.

Use of Estimates

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, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. 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.

7

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations 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. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Restricted Cash

Restricted cash represents a portion of the cash paid for the Loving County Processing System by EnLink (as described in Note 5) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to the Company by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $15.7 million, $6.9 million and $6.4 million of its general and administrative costs in 2016, 2015 and 2014, respectively. The Company capitalized $3.7 million, $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a

8

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2014, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014.

9

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

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 sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s 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.

Other Property and Equipment

Other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using 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. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments.

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable.

For the year ended December 31, 2016, three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). For the year ended December 31, 2015, three significant purchasers accounted for 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (33%), Enterprise Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). For the year ended December 31, 2014, three significant purchasers accounted for approximately 68% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (45%), Enterprise Crude Oil LLC (12%) and Enterprise Products Operating LLC (11%). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2016, 2015 and 2014, approximately 38%, 39% and 44%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

10

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 include a stock-based compensation (non-cash) expense of $12.4 million, $9.5 million and $5.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.0 million, $0.9 million and $0.3 million in 2016, 2015 and 2014, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2016, 2015 and 2014, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2016, 2015 and 2014.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

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 (loss) per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share data).

11

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

	Year Ended December 31,
	2016			2015			2014
Net (loss) income attributable to Matador Resources Company shareholders — numerator	$	(97,421	)	$	(679,785	)	$	110,771
Weighted average common shares outstanding — denominator
Basic	91,273			81,537			70,229
Dilutive effect of options, restricted stock units and preferred shares	—			—			677
Diluted weighted average common shares outstanding	91,273			81,537			70,906
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	(1.07	)	$	(8.34	)	$	1.58
Diluted	$	(1.07	)	$	(8.34	)	$	1.56

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company.

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2016 were with Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s Credit Agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

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

12

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

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

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

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

13

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2016 and 2015 (in thousands).

	December 31,
	2016			2015
Oil and natural gas properties
Evaluated (subject to amortization)	$	2,408,305		$	2,122,174
Unproved and unevaluated (not subject to amortization)	479,736			387,504
Total oil and natural gas properties	2,888,041			2,509,678
Accumulated depletion	(1,850,882		)	(1,574,040		)
Net oil and natural gas properties	1,037,159			935,638
Other property and equipment
Midstream equipment and facilities	145,662			78,564
Furniture, fixtures and other equipment	5,487			2,918
Software	3,206			2,193
Land	1,437			1,539
Leasehold improvements	5,003			1,173
Total other property and equipment	160,795			86,387
Accumulated depreciation	(13,429		)	(9,619		)
Net other property and equipment	147,366			76,768
Net property and equipment	$	1,184,525		$	1,012,406

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2016 and the year in which these costs were incurred (in thousands).

Description	2016		2015		2014		2013 and prior		Total
Costs incurred for
Property acquisition	$	126,857	$	236,507	$	55,258	$	23,654	$	442,276
Exploration wells	19,017		3,375		34		—		22,426
Development wells	13,086		1,218		730		—		15,034
Total	$	158,960	$	241,100	$	56,022	$	23,654	$	479,736

Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2016 are related primarily to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past four years. These costs include, in particular, the cost of the acreage acquired as part of the HEYCO Merger (as described and defined in Note 5) in 2015. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties which are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $37.5 million at December 31, 2016. Of this

14

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

total, $22.4 million was associated with exploration wells and $15.0 million was associated with development wells. The Company anticipates that most of the $37.5 million associated with these wells in progress at December 31, 2016 will be transferred to the amortization base during 2017.

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2016 and 2015 (in thousands).

	Year Ended December 31,
	2016			2015
Beginning asset retirement obligations	$	15,420		$	11,951
Liabilities incurred during period	1,791			4,508
Liabilities settled during period	(375		)	(588		)
Revisions in estimated cash flows	2,622			(1,185		)
Accretion expense	1,182			734
Ending asset retirement obligations	20,640			15,420
Less: current asset retirement obligations (1)	(915		)	(254		)
Long-term asset retirement obligations	$	19,725		$	15,166

__________________

(1) Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2016 and 2015.

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES

Business Combinations

On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross (18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction.

As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Matador incurred an additional $4.5 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing.  The consideration paid and the liabilities assumed, including deferred tax liabilities of approximately $76.8 million and other liabilities of approximately $4.5 million, represent a total purchase price of $223.5 million. The HEYCO Merger was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date.

15

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage. The producing wells acquired in the HEYCO Merger did not have a material impact on the Company’s revenues or results of operations for the year ended December 31, 2015. During the year ended December 31, 2015, the Company incurred approximately $2.5 million of transaction costs associated with the HEYCO Merger, which were included in “General and administrative” costs in the consolidated statement of operations.

Divestitures

On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and the Company received net proceeds of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million. In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15-year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement.

Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and processing agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink is now processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink is no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016.

The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017 these assets were contributed to the Joint Venture (as described and defined in Note 18).

NOTE 6 — DEBT

Credit Agreement

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million. MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company.

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. On October 31, 2016, the borrowing base was increased from $300.0 million to $400.0 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at June 30, 2016

16

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 6 — DEBT — Continued

using commodity price estimates prescribed by the lenders. This borrowing base increase was primarily attributable to increases in both the Company’s proved reserves volumes and increases in oil and natural gas prices in the latter part of 2016. All other provisions of the Credit Agreement remained unchanged. This October 2016 redetermination constituted the regularly scheduled November 1 redetermination. The Credit Agreement matures on October 16, 2020.

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 were $1.3 million at December 31, 2016, and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.

During the year ended December 31, 2016, using a portion of the net proceeds from the December 2016 senior unsecured notes offering and the public offering of our common stock discussed herein, the Company repaid a total of $120.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2016, the Company had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. At February 22, 2017, the Company continued to have no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company.

A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:

• incur indebtedness or grant liens on any of the Company’s assets;

• enter into commodity hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with affiliates;

• engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and

• take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

17

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 6 — DEBT — Continued

• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;

• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving the Company or its subsidiaries; and

• a change of control, as defined in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2016.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes are Matador’s senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original Notes mature on April 15, 2023 and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On October 21, 2015, and pursuant to a registered exchange offer, the Company exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes.

On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes” and, collectively with the Registered Notes, the “Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5%. We received net proceeds from the Notes Offering of approximately $181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. A portion of the net proceeds of the Notes Offering, along with the proceeds from the December 2016 public offering of our common stock, have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig. The Notes are our senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated.

Year	Redemption Price
2018	105.156%
2019	103.438%
2020	101.719%
2021 and thereafter	100.000%

At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.

18

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 6 — DEBT — Continued

In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date.

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:

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

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

• transfer or sell assets;

• make certain investments;

• create certain liens;

• enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company;

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

• engage in transactions with affiliates; and

• create unrestricted subsidiaries.

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:

• default for 30 days in the payment when due of interest on the Notes;

• default in the payment when due of the principal of, or premium, if any, on the Notes;

• failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets;

• failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;

• failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;

• payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more;

• failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days;

• any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and

• certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

19

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 7 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2016 and 2015, respectively, is as follows (in thousands).

	December 31,
	2016			2015
Deferred tax assets
Unrealized loss on derivatives	$	8,734		$	—
Net operating loss carryforwards	137,757			79,208
Alternative minimum tax carryforward	8,633			9,785
Percentage depletion carryover	2,595			2,442
Property and equipment	44,391			42,757
Deferred gain on sale leaseback transaction	—			32,831
Other	—			7,396
Total deferred tax assets	202,110			174,419
Valuation allowance on deferred tax assets	(190,255		)	(154,320		)
Total deferred tax assets, net of valuation allowance	11,855			20,099
Deferred tax liabilities
Unrealized gain on derivatives	(3,800		)	(5,699		)
Other	(8,055		)	(14,400		)
Total deferred tax liabilities	(11,855		)	(20,099		)
Net deferred tax liabilities	$	—		$	—

At December 31, 2016, the Company had net operating loss carryforwards of $375.9 million for federal income tax purposes and $6.2 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the State of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company recorded an impairment charge of $158.6 million and $801.2 million, respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2016 and 2015, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2015 and 2016. As a result, at December 31, 2016 and 2015, the Company maintained a valuation allowance against the Company’s federal and state deferred tax assets. The valuation allowance will continue to be recognized until the realization of future tax benefits are more likely than not to be utilized.

20

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 7 — INCOME TAXES — Continued

The current income tax provision for the years ended December 31, 2016, 2015 and 2014, respectively, was comprised of the following (in thousands).

	Year Ended December 31,
	2016			2015		2014
Current income tax provision
State income tax	$	108		$	371	$	—
Federal alternative minimum tax	(1,144		)	2,588		133
Net current income tax (benefit) provision	$	(1,036	)	$	2,959	$	133

Reconciliations of the tax (benefit) expense computed at the statutory federal rate to the Company’s total income tax (benefit) provision for the years ended December 31, 2016, 2015 and 2014, respectively, is as follows (in thousands).

	Year Ended December 31,
	2016			2015			2014
Federal tax (benefit) expense at statutory rate (1)	$	(34,333	)	$	(289,412	)	$	61,301
State income tax	539			(13,215		)	2,707
Permanent differences (2)	(499		)	698			397
Federal alternative minimum tax	1,144			(2,588		)	(133		)
Change in federal valuation allowance	33,688			145,777			—
Change in state valuation allowance	(539		)	8,413			(30		)
Net deferred income tax (benefit) provision	—			(150,327		)	64,242
Net current income tax (benefit) provision	(1,036		)	2,959			133
Total income tax (benefit) provision	$	(1,036	)	$	(147,368	)	$	64,375

__________________    

(1) The statutory federal tax rate was 35% for the years ended December 31, 2016, 2015 and 2014.

(2) Amount is primarily attributable to stock-based compensation.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2012. The earliest tax year open for examination by the State of Texas is 2009. During the year ended December 31, 2016, the Company’s 2009 and 2010 franchise tax returns were under examination by the State of Texas. This examination has been completed with no additional tax due; however, the examination has not been formally closed. In addition, as of December 31, 2016, the Company’s 2013 federal income tax return was under examination by the Internal Revenue Service. This examination has been completed with no additional tax due; however, the examination has not been formally closed.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2016, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 8 — STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company.

In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2016, the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years.

The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.14 years	0.39 years	1.51 years
Risk-free interest rate	1.70%	0.64%	0.74%
Volatility	47.07%	91.98%	55.14%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.96 years	4.00 years	3.99 years
Risk-free interest rate	1.08%	1.15%	1.21%
Volatility	45.68%	56.89%	51.47%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	1.16%	3.21%	4.28%
Weighted average fair value of stock option awards granted during the year	$5.65	$9.90	$9.45

22

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 8 — STOCK-BASED COMPENSATION — Continued

The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2016 under the 2003 Plan and the 2012 Incentive Plan is as follows.

	Number of options (in thousands)		Weighted average exercise price
Options outstanding at December 31, 2015	2,363		$	15.40
Options granted	668		$	15.51
Options exercised	(114	)	$	10.12
Options forfeited	(28	)	$	19.73
Options expired	(2	)	$	22.66
Options outstanding at December 31, 2016	2,887		$	15.59

	Options outstanding at December 31, 2016				Options exercisable at December 31, 2016
Range of exercise prices	Shares outstanding (in thousands)	Weighted average remaining contractual life	Weighted average exercise price		Shares exercisable (in thousands)	Weighted average exercise price
$8.18 - $9.55	816	1.30	$	8.30	484	$	8.35
$10.49 - $17.80	925	2.87	$	13.55	302	$	10.58
$18.77 - $22.70	862	3.05	$	21.84	65	$	21.21
$23.40 - $27.33	284	2.26	$	24.22	112	$	23.49

At December 31, 2016, the aggregate intrinsic value was $29.4 million for outstanding options and $13.6 million for exercisable options, based on the Company’s quoted closing market price of $25.76 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2016 was 1.19 years.

The total intrinsic value of options exercised during the years ended December 31, 2016, 2015 and 2014 was $1.6 million, $1.3 million and $0.2 million, respectively. The tax related benefit realized from the exercise of stock options totaled $0.5 million, $0.3 million and $0.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

During the years ended December 31, 2016, 2015 and 2014, the Company recognized $5.9 million, $4.7 million and $2.5 million, respectively, in stock-based compensation expense attributable to stock options. At December 31, 2016, 2015 and 2014, the Company had recorded $1.4 million, zero and $1.4 million of long-term liabilities and zero, $1.0 million and zero of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2016, 2015 and 2014, respectively.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested stock options was approximately $6.9 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.90 years.

The fair value of options vested during 2016, 2015 and 2014 was $3.0 million, $1.3 million and $1.5 million, respectively.

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient

23

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 8 — STOCK-BASED COMPENSATION — Continued

makes an election to defer issuance for a set term after vesting. One current director elected to defer the issuance of his awards in 2015, 2014 and 2013. All awards granted in 2016, 2015 and 2014 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2016 were granted under the 2012 Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2016 is presented below (in thousands, except fair value).

	Restricted Stock				Restricted Stock Units
Non-vested restricted stock and restricted stock units	Shares		Weighted average fair value		Shares		Weighted average fair value
Non-vested at December 31, 2015	854		$	17.64	68		$	21.89
Granted	472		$	18.55	66		$	19.44
Vested	(225	)	$	16.05	(52	)	$	19.67
Forfeited	(62	)	$	20.49	—		—
Non-vested at December 31, 2016	1,039		$	18.23	82		$	21.32

At December 31, 2016, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $28.9 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $25.76 per share on that date.

During the years ended December 31, 2016, 2015 and 2014, the Company recognized approximately $6.6 million, $4.7 million and $3.0 million, respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $12.5 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.8 years.

The fair value of restricted stock and restricted stock units vested during 2016, 2015 and 2014 was $4.6 million, $0.8 million and $0.9 million, respectively.

The total tax benefit recognized for all stock-based compensation was $4.3 million, $3.4 million and $1.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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

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

NOTE 9 — EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled approximately $0.7 million, $0.6 million and $0.4 million in 2016, 2015 and 2014, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $0.9 million, $0.8 million and $0.5 million in 2016, 2015 and 2014, respectively. The Company made no additional discretionary contributions in any reporting period presented.

24

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 10 — EQUITY

Stock Offerings, Retirement and Issuances

On December 9, 2016, the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million, the Company received net proceeds of approximately $145.8 million. A portion of the net proceeds of the public offering, along with the proceeds from the Notes Offering (see Note 6), have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig.

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 were used for general corporate purposes, including to fund a portion of the Company’s 2016 capital expenditures.

As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock.

On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2016 to satisfy certain conditions under the merger agreement.

On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million, the Company received net proceeds of approximately $187.6 million.

On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million, the Company received net proceeds of approximately $181.3 million.

Treasury Stock

On October 27, 2016, October 30, 2015 and October 31, 2014, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2016, September 30, 2015 and September 30, 2014, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2016, 2015 and 2014 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees.

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using 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. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments.

The Company typically uses 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 the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.

25

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

At December 31, 2016, we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period.

When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume

At December 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 2017 and 2018.

26

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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

		Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Liabilities (thousands)
Commodity	Calculation Period
Oil	01/01/2017 - 12/31/2017	2,760,000	$	41.39	$	51.88	$	(18,316	)
Oil	01/01/2018 - 12/31/2018	720,000	$	43.75	$	63.90	(751		)
Natural Gas	01/01/2017 - 12/31/2017	16,860,000	$	2.40	$	3.59	(5,887		)
Total open derivative financial instruments							$	(24,954	)

Subsequent to December 31, 2016, the Company entered into various costless collar contracts for oil. The costless collar contracts for oil included approximately 1,890,000 Bbl in 2017 with a weighted average floor price of $50.00 per Bbl and a weighted average ceiling price of $60.75 per Bbl.

From time-to-time we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlements 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 consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2016 and December 31, 2015 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)
December 31, 2015
Current assets	$	16,767		$	(483	)	$	16,284
Current liabilities	(483		)	483			—
Total	$	16,284		$	—		$	16,284

27

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

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

		Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2016			2015			2014
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	5,851		$	62,259		$	5,221
Natural Gas	Revenues: Realized gain (loss) on derivatives	3,435			12,653			(718		)
Natural Gas Liquids (NGL)	Revenues: Realized gain on derivatives	—			2,182			519
Realized gain on derivatives		9,286			77,094			5,022
Oil	Revenues: Unrealized (loss) gain on derivatives	(18,969		)	(31,897		)	47,178
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(22,269		)	(5,440		)	9,087
Natural Gas Liquids (NGL)	Revenues: Unrealized (loss) gain on derivatives	—			(1,928		)	2,037
Unrealized (loss) gain on derivatives		(41,238		)	(39,265		)	58,302
Total		$	(31,952	)	$	37,829		$	63,324

28

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 12 — FAIR VALUE MEASUREMENTS

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

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

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

Level 3 Unobservable inputs that are not corroborated by market data 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.

At December 31, 2016 and 2015, the carrying values reported on the 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 approximate their fair values due to their short-term maturities.

At December 31, 2016 and 2015, the fair value of the Company’s Notes was $605.2 million and $381.0 million, respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy.

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 December 31, 2016 and 2015 (in thousands).

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

	Fair Value Measurements at December 31, 2015 using
Description
	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
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 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy.

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination (see Note 5), lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for

29

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 12 — FAIR VALUE MEASUREMENTS — Continued

sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2016 and 2015. The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions.

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026. The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease.

From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties.

The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2016 (in thousands).

Year Ending December 31,	Amount
2017	$	2,443
2018	2,495
2019	2,528
2020	2,602
2021	2,660
Thereafter	12,335
Total	$	25,063

Rent expense, including fees for operating expenses and consumption of electricity, was $2.9 million, $1.7 million, and $0.9 million for 2016, 2015 and 2014, respectively.

Natural Gas and NGL Processing and Transportation Commitments

Eagle Ford

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

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid approximately $3.0 million and $5.5 million in processing and transportation fees under this agreement during the years ended December 31, 2016 and 2015, respectively. The future undiscounted minimum payment under this agreement as of December 31, 2016 is $1.2 millionin 2017.

Delaware Basin

As part of the sale of the Loving County Processing System (see Note 5), the Company entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume

30

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued

commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2016, the total deficiency fee required to be paid would be approximately $11.7 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 $9.8 million and $1.8 million in processing and gathering fees under this agreement during the years ended December 31, 2016 and 2015, respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for two years or less. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $46.3 million at December 31, 2016.

At December 31, 2016, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $11.1 million at December 31, 2016. The Company expects these costs to be incurred within the next year.

Legal Proceedings

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

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Matador Resources Company and Subsidiaries

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December 31, 2016, 2015 and 2014

NOTE 14 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

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

	December 31,
	2016		2015
Accrued evaluated and unproved and unevaluated property costs	$	54,273	$	54,586
Accrued support equipment and facilities costs	15,139		17,393
Accrued lease operating expenses	16,009		7,743
Accrued interest on debt	6,541		5,806
Accrued asset retirement obligations	915		254
Accrued partners’ share of joint interest charges	5,572		4,565
Other	3,011		2,022
Total accrued liabilities	$	101,460	$	92,369

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Cash paid for income taxes	$	2,895		$	506		$	94
Cash paid for interest expense, net of amounts capitalized	27,464			16,154			5,269
Increase in asset retirement obligations related to mineral properties	3,817			2,510			3,843
Increase in asset retirement obligations related to support equipment and facilities	222			383			120
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	1,775			(30,683		)	32,972
(Decrease) increase in liabilities for support equipment and facilities	(588		)	12,076			4,290
Issuance of restricted stock units for Board and advisor services	992			584			444
Stock-based compensation expense recognized as liability	569			79			223
Increase in liabilities for accrued cost to issue equity	343			—			—
Transfer of inventory to oil and natural gas properties	395			615			216

NOTE 15 — SUBSIDIARY GUARANTORS

Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the Company issued the Original Notes and on December 9, 2016, the Company issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries” and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2016, the Guarantor Subsidiaries were 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries were 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.

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Matador Resources Company and Subsidiaries

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December 31, 2016, 2015 and 2014

NOTE 16 — RELATED PARTY TRANSACTIONS

In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2016, the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities.

NOTE 17 — SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During the third quarter of 2016, our midstream business became a reportable segment under U.S. GAAP. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

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

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 17 — SEGMENT INFORMATION — Continued

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2016
Oil and natural gas revenues	$	289,512		$	1,644	$	—		$	—		$	291,156
Midstream services revenues	—			18,982		—			(13,764		)	5,218
Realized gain on derivatives	9,286			—		—			—			9,286
Unrealized gain on derivatives	(41,238		)	—		—			—			(41,238		)
Expenses (1)	391,098			8,254		56,001			(13,764		)	441,589
Operating (loss) income (2)	$	(133,538	)	$	12,372	$	(56,001	)	$	—		$	(177,167	)
Total Assets	$	1,098,525		$	140,459	$	225,681		$	—		$	1,464,665
Capital Expenditures	$	379,881		$	67,566	$	6,913		$	—		$	454,360

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $118.4 million, $2.7 million and $0.9 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.

(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2015
Oil and natural gas revenues	$	277,844		$	496	$	—		$	—		$	278,340
Midstream services revenues	—			11,485		—			(9,621		)	1,864
Realized gain on derivatives	77,094			—		—			—			77,094
Unrealized loss on derivatives	(39,265		)	—		—			—			(39,265		)
Expenses (1)	1,078,534			5,178		50,604			(9,621		)	1,124,695
Operating (loss) income (2)	$	(762,861	)	$	6,803	$	(50,604	)	$	—		$	(806,662	)
Total Assets	$	1,000,075		$	75,980	$	64,806		$	—		$	1,140,861
Capital Expenditures (3)	$	622,642		$	75,009	$	786		$	—		$	698,437

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $176.7 million, $1.6 million and $0.5 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment.

(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) In October 2015, the Company sold the Wolf Processing Plant to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets.

34

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 17 — SEGMENT INFORMATION — Continued

	Exploration and Production										Consolidated Company
			Midstream		Corporate			Eliminations
Year Ended December 31, 2014
Oil and natural gas revenues	$	366,191	$	1,521	$	—		$	—		$	367,712
Midstream services revenues	—		4,929		—			(3,716		)	1,213
Realized gain on derivatives	5,022		—		—			—			5,022
Unrealized loss on derivatives	58,302		—		—			—			58,302
Expenses (1)	220,374		2,703		32,557			(3,716		)	251,918
Operating (loss) income (2)	$	209,141	$	3,747	$	(32,557	)	$	—		$	180,331
Total Assets	$	1,388,261	$	35,100	$	11,129		$	—		$	1,434,490
Capital Expenditures	$	597,351	$	12,504	$	517		$	—		$	610,372

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $133.1 million, $1.2 million and $0.4 million for the exploration and production, midstream and corporate segments, respectively.

(2) Includes $17,000 in net loss attributable to non-controlling interest in subsidiaries related to the midstream segment.

35

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 18 — SUBSEQUENT EVENTS

Subsequent to December 31, 2016, the Company acquired approximately 13,900 gross (8,200 net) leased and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around its existing acreage in the Delaware Basin. The cost of these acquisitions was approximately $111 million.

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

The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution. The Company may earn an additional $73.5 million in performance incentives over the next five years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140 million in the aggregate to expand the Joint Venture’s midstream operations and asset base.

In connection with the Joint Venture, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed fee natural gas processing agreement (when combined with the gathering and salt water disposal agreements, the “Operational Agreements”). The Joint Venture will provide the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at inception was approximately $273.5 million.

The following unaudited pro forma consolidated financial information is presented to illustrate the effect on the historical operating results and financial position of the Company of (a) the formation of San Mateo and the transactions associated with the Joint Venture and (b) the Company’s acquisition on February 14, 2017 of the remaining non-controlling interest in Fulcrum Delaware Water Resources, LLC (“Fulcrum Delaware Water Resources”) not previously owned by the Company for approximately $2.6 million (collectively, the “Transactions”).

The Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2016, if presented, would contain an adjustment of $4.5 million to increase the net income attributable to non-controlling interest in subsidiaries from $0.4 million to $4.9 million, which would increase the net loss attributable to Matador Resources Company shareholders from $97.4 million to $102.0 million, and an adjustment of $0.05 per diluted common share to increase the net loss per diluted common share attributable to Matador Resources Company shareholders from $1.07 to $1.12.

The following Unaudited Pro Forma Consolidated Balance Sheet as of December 31, 2016, presented for illustrative purposes, is based on the historical financial statements of the Company as of December 31, 2016, after giving effect to the Transactions as if they had occurred on December 31, 2016.

36

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 18 — SUBSEQUENT EVENTS — Continued

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

	December 31, 2016
	As Reported			Adjustment			Pro Forma
ASSETS
Current assets
Cash	$	212,884		$	164,340	(1)	$	377,224
Restricted cash	1,258			9,407		(2)	10,665
Accounts receivable							—
Oil and natural gas revenues	34,154			—			34,154
Joint interest billings	19,347			—			19,347
Other	5,167			—			5,167
Lease and well equipment inventory	3,045			—			3,045
Prepaid expenses and other assets	3,327			—			3,327
Total current assets	279,182			173,747			452,929
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,408,305			—			2,408,305
Unproved and unevaluated	479,736			—			479,736
Other property and equipment	160,795			—			160,795
Less accumulated depletion, depreciation and amortization	(1,864,311		)	—			(1,864,311		)
Net property and equipment	1,184,525			—			1,184,525
Other assets	958						958
Total assets	$	1,464,665		$	173,747		$	1,638,412
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	4,674		$	—		$	4,674
Accrued liabilities	101,460			—			101,460
Royalties payable	23,988			—			23,988
Amounts due to affiliates	8,651			—			8,651
Derivative instruments	24,203			—			24,203
Advances from joint interest owners	1,700			—			1,700
Amounts due to joint ventures	4,251			—			4,251
Other current liabilities	578			—			578
Total current liabilities	169,505			—			169,505
Long-term liabilities
Senior unsecured notes payable	573,924			—			573,924
Asset retirement obligations	19,725			—			19,725
Derivative instruments	751			—			751
Amounts due to joint ventures	1,771			—			1,771
Other long-term liabilities	7,544			—			7,544
Total long-term liabilities	603,715			—			603,715
Commitments and contingencies (Note 13)
Shareholders’ equity
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995			—			995
Additional paid-in capital	1,325,481			124,871		(3)	1,450,352
Accumulated deficit	(636,351		)	—			(636,351		)
Total Matador Resources Company shareholders’ equity	690,125			124,871			814,996
Non-controlling interest in subsidiaries	1,320			48,876		(4)	50,196
Total shareholders’ equity	691,445			173,747			865,192
Total liabilities and shareholders’ equity	$	1,464,665		$	173,747		$	1,638,412

______________________

(1) Represents $176.4 million of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately $2.6 million paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and (ii) $10.0

37

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 18 — SUBSEQUENT EVENTS — Continued

million of cash restricted to operations of San Mateo. Also reflects $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources not previously owned by the Company.

(2) Represents $10.0 million in cash contributed to San Mateo less $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own.

(3) Reflects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the amount received in connection with the formation of San Mateo.

(4) Represents the adjustment required to reflect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and Five Point’s 49% non-controlling interest in San Mateo.

38

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 19 — GUARANTOR FINANCIAL INFORMATION

On December 9, 2016, the Company issued the Additional Notes (see Note 6), which, at the time of issuance and as of December 31, 2016, were jointly and severally guaranteed by the Notes Guarantor Subsidiaries (see Note 15). On February 17, 2017, in connection with the formation of San Mateo (see Note 18), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the Indenture (see Note 6). Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Existing Guarantor Subsidiaries.” San Mateo and its subsidiaries are not guarantors of the Notes.

The following presents condensed consolidating financial information as of December 31, 2016 and 2015 and for each of the years in the three-year period ended December 31, 2016 on an issuer (Matador), Non-Guarantor Subsidiaries, Existing Guarantor Subsidiaries and consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Existing Guarantor Subsidiaries operated as independent entities.

39

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 19 — GUARANTOR FINANCIAL INFORMATION — Continued

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

Condensed Consolidating Balance Sheet December 31, 2015
	Matador		Non-Guarantor Subsidiaries		Existing Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	304,573	$	1,463	$	11,928	$	(317,964	)	$	—
Other current assets	289		1,141		125,577		—			127,007
Net property and equipment	—		47,535		964,871		—			1,012,406
Investment in subsidiaries	584,461		—		20,355		(604,816		)	—
Other long-term assets	—		—		1,448		—			1,448
Total assets	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	$	1,140,861
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	11,928	$	306,036	$	(317,964	)	$	—
Other current liabilities	10,066		16,557		110,207		—			136,830
Senior unsecured notes payable	391,254		—		—		—			391,254
Other long-term liabilities	—		343		123,475		—			123,818
Total equity attributable to Matador Resources Company	488,003		20,355		584,461		(604,816		)	488,003
Non-controlling interest in subsidiaries	—		956		—		—			956
Total liabilities and equity	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	1,140,861

40

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 19 — GUARANTOR FINANCIAL INFORMATION — Continued

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	17,302		$	257,828		$	(10,708	)	$	264,422
Total expenses	5,319			7,031			439,947			(10,708		)	441,589
Operating (loss) income	(5,319		)	10,271			(182,119		)	—			(177,167		)
Net gain on asset sales and inventory impairment	—			—			107,277			—			107,277
Interest expense	(28,199		)	—			—			—			(28,199		)
Other expense	—			—			(4		)	—			(4		)
(Loss) earnings in subsidiaries	(64,349		)	—			9,810			54,539			—
(Loss) income before income taxes	(97,867		)	10,271			(65,036		)	54,539			(98,093		)
Total income tax (benefit) provision	(446		)	97			(687		)	—			(1,036		)
Net income attributable to non-controlling interest in subsidiaries	—			(364		)	—			—			(364		)
Net (loss) income attributable to Matador Resources Company	$	(97,421	)	$	9,810		$	(64,349	)	$	54,539		$	(97,421	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	6,310		$	316,067		$	(4,344	)	$	318,033
Total expenses	5,739			2,944			1,120,356			(4,344		)	1,124,695
Operating (loss) income	(5,739		)	3,366			(804,289		)	—			(806,662		)
Net gain on asset sales and inventory impairment	—			—			908			—			908
Interest expense	(20,511		)	—			(1,243		)	—			(21,754		)
Other income	—			—			616			—			616
(Loss) earnings in subsidiaries	(658,698		)	—			2,458			656,240			—
(Loss) income before income taxes	(684,948		)	3,366			(801,550		)	656,240			(826,892		)
Total income tax (benefit) provision	(5,163		)	647			(142,852		)	—			(147,368		)
Net income attributable to non-controlling interest in subsidiaries	—			(261		)	—			—			(261		)
Net (loss) income attributable to Matador Resources Company	$	(679,785	)	$	2,458		$	(658,698	)	$	656,240		$	(679,785	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	—		$	432,249		$	—		$	432,249
Total expenses	3,389			111			248,418			—			251,918
Operating (loss) income	(3,389		)	(111		)	183,831			—			180,331
Net gain on asset sales and inventory impairment	—			—			—			—			—
Interest expense	—			—			(5,334		)	—			(5,334		)
Other income	—			—			132			—			132
Earnings (loss) in subsidiaries	112,908			—			(94		)	(112,814		)	—
Income (loss) before income taxes	109,519			(111		)	178,535			(112,814		)	175,129
Total income tax (benefit) provision	(1,252		)	—			65,627			—			64,375
Net loss attributable to non-controlling interest in subsidiaries	—			17			—			—			17
Net income (loss) attributable to Matador Resources Company	$	110,771		$	(94	)	$	112,908		$	(112,814	)	$	110,771

41

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2016, 2015 and 2014

NOTE 19 — GUARANTOR FINANCIAL INFORMATION — Continued

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(45,215	)	$	6,694		$	172,607		$	—		$	134,086
Net cash used in investing activities	(324,724		)	(64,683		)	(401,034		)	384,801			(405,640		)
Net cash provided by financing activities	469,654			60,110			322,743			(384,801		)	467,706
Increase in cash	99,715			2,121			94,316			—			196,152
Cash at beginning of year	80			186			16,466			—			16,732
Cash at end of year	$	99,795		$	2,307		$	110,782		$	—		$	212,884

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(31,271	)	$	13,916		$	225,890		$	—		$	208,535
Net cash used in investing activities	(546,715		)	(31,101		)	(410,843		)	563,505			(425,154		)
Net cash provided by financing activities	577,973			17,353			193,123			(563,505		)	224,944
Increase in cash	(13		)	168			8,170			—			8,325
Cash at beginning of year	93			18			8,296			—			8,407
Cash at end of year	$	80		$	186		$	16,466		$	—		$	16,732

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(8,607	)	$	431		$	259,657		$	—		$	251,481
Net cash used in investing activities	(172,749		)	(1,763		)	(569,968		)	173,949			(570,531		)
Net cash provided by financing activities	181,328			1,350			312,441			(173,949		)	321,170
Increase in cash	(28		)	18			2,130			—			2,120
Cash at beginning of year	121			—			6,166			—			6,287
Cash at end of year	$	93		$	18		$	8,296		$	—		$	8,407

42

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016		2015		2014
Property acquisition costs
Proved	$	—	$	16,524	$	2,728
Unproved and unevaluated	108,206		253,923		78,484
Exploration costs	113,562		122,495		156,178
Development costs	158,113		229,700		359,961
Total costs incurred (1)	$	379,881	$	622,642	$	597,351

__________________

(1) Excludes midstream-related development and corporate costs of approximately $74.5 million, $75.8 million and $13.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2016, 2015 and 2014, most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities.

Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.4 million, $3.3 million and $4.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $15.7 million, $6.9 million and $6.4 million of these internal costs in 2016, 2015 and 2014, respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $3.7 million, $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015 and 2014, respectively.

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value

43

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2016, 2015 and 2014 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.

44

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

	Net Proved Reserves
	Oil		Natural Gas		Oil Equivalent
	(MBbl)		(MMcf)		(MBOE)
Total at December 31, 2013	16,362		212,195		51,729
Revisions of prior estimates	(1,196	)	164		(1,169	)
Purchases of minerals in-place	10		433		82
Extensions and discoveries	12,328		69,566		23,921
Production	(3,320	)	(15,303	)	(5,870	)
Total at December 31, 2014	24,184		267,055		68,693
Revisions of prior estimates	(2,609	)	(75,433	)	(15,181	)
Purchases of minerals in-place	1,102		2,927		1,589
Extensions and discoveries	27,459		70,054		39,135
Production	(4,492	)	(27,702	)	(9,109	)
Total at December 31, 2015	45,644		236,901		85,127
Revisions of prior estimates	(6,440	)	(28,481	)	(11,187	)
Extensions and discoveries	22,869		114,730		41,992
Production	(5,096	)	(30,501	)	(10,180	)
Total at December 31, 2016	56,977		292,649		105,752
Proved Developed Reserves
December 31, 2013	8,258		53,458		17,168
December 31, 2014	14,053		102,795		31,185
December 31, 2015	17,129		101,447		34,037
December 31, 2016	22,604		126,759		43,731
Proved Undeveloped Reserves
December 31, 2013	8,104		158,737		34,561
December 31, 2014	10,131		164,260		37,508
December 31, 2015	28,515		135,454		51,090
December 31, 2016	34,373		165,890		62,021

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2016, 2015 and 2014.

The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from 85,127 MBOE at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 30,805 MBOE and the Company produced 10,180 MBOE during the year ended December 31, 2016, resulting in a net increase of 20,625 MBOE. An increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 11,187 MBOE during 2016 as a result of the reclassification of proved undeveloped reserves to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate proved reserves during 2016, as compared to 2015. The Company anticipates that these contingent resources may be reclassified to proved undeveloped reserves in future periods should the oil and natural gas prices used to estimate proved reserves improve from the prices at December 31, 2016. The Company’s proved developed oil and natural gas reserves increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2016, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 41% proved developed and approximately 59% proved undeveloped.

The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from 68,693 MBOE at December 31, 2014. The Company’s proved oil and natural gas reserves increased by 25,543 MBOE and the Company produced 9,109 MBOE during the year ended December 31, 2015, resulting in a net increase of 16,434 MBOE. An

45

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the removal of 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015, as well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves, primarily in the Haynesville shale in Northwest Louisiana, primarily resulting from the decline in commodity prices during 2015. The Company also purchased minerals in-place with proved reserves of 1,589 MBOE in 2015, primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2015, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately 60% proved undeveloped.

The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from 51,729MBOE at December 31, 2013. The Company’s proved oil and natural gas reserves increased by 22,834 MBOE and the Company produced 5,870 MBOE during the year ended December 31, 2014, resulting in a net increase of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, plus additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014. The Company also purchased minerals in-place with proved reserves of 82 MBOE in 2014. The Company’s proved developed oil and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31, 2013, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Delaware Basin plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014, the Company’s proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates.

As noted previously, for the period from January through December 2016, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, the comparable average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, the comparable average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively.

Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows.

46

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Future cash inflows	$	2,684,877		$	2,461,131		$	3,197,317
Future production costs	(927,725		)	(843,117		)	(803,662		)
Future development costs	(630,280		)	(615,692		)	(553,799		)
Future income tax expense	(24,742		)	(43,956		)	(321,088		)
Future net cash flows	1,102,130			958,366			1,518,768
10% annual discount for estimated timing of cash flows	(527,087		)	(429,185		)	(605,449		)
Standardized measure of discounted future net cash flows	$	575,043		$	529,181		$	913,319

The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Balance, beginning of period	$	529,181		$	913,319		$	578,668
Net change in sales and transfer prices and in production (lifting) costs related to future production	(92,477		)	(509,901		)	87,067
Changes in estimated future development costs	(74,142		)	(145,861		)	(150,447		)
Sales and transfers of oil and natural gas produced during the period	(191,908		)	(184,612		)	(283,187		)
Purchases of reserves in place	—			16,321			1,838
Net change due to extensions and discoveries	360,033			401,895			537,472
Net change due to revisions in estimates of reserves quantities	(95,917		)	(285,823		)	(26,263		)
Previously estimated development costs incurred during the period	84,519			121,543			187,459
Accretion of discount	51,779			82,574			65,518
Other	(1,962		)	2,029			5,492
Net change in income taxes	5,937			117,697			(90,298		)
Standardized measure of discounted future net cash flows	$	575,043		$	529,181		$	913,319

47

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2016, 2015 and 2014

SELECTED QUARTERLY FINANCIAL INFORMATION

The following table presents selected unaudited quarterly financial information for 2016 (in thousands, except per share data).

	December 31			September 30			June 30			March 31
2016
Oil and natural gas revenues	$	94,815		$	83,079		$	69,336		$	43,926
Third-party midstream services revenues	2,261			1,566			918			473
Realized (loss) gain on derivatives	(1,127		)	885			2,465			7,063
Unrealized (loss) gain on derivatives	(10,977		)	3,203			(26,625		)	(6,839		)
Expenses (1)	76,753			71,879			146,705			146,252
Other income (expense) (2)	96,196			(5,948		)	(5,136		)	(6,038		)
Income (loss) before income taxes	104,415			10,906			(105,747		)	(107,667		)
Income tax provision (benefit)	105			(1,141		)	—			—
Net income (loss)	104,310			12,047			(105,747		)	(107,667		)
Net (income) loss attributable to non-controlling interest in subsidiaries	(155		)	(116		)	(106		)	13
Net income (loss) attributable to Matador Resources Company shareholders	$	104,155		$	11,931		$	(105,853	)	$	(107,654	)
Earnings (loss) per common share
Basic	$	1.10		$	0.13		$	(1.15	)	$	(1.26	)
Diluted	$	1.09		$	0.13		$	(1.15	)	$	(1.26	)

__________________

(1) Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million, and $80.5 million, respectively.

(2) Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million. See Note 5.

The following table presents selected unaudited quarterly financial information for 2015 (in thousands, except per share data).

	December 31			September 30			June 30			March 31
2015
Oil and natural gas revenues	$	56,212		$	71,815		$	87,848		$	62,465
Third-party midstream services revenues	480			569			464			351
Realized gain on derivatives	24,948			19,862			13,780			18,504
Unrealized (loss) gain on derivatives	(13,909		)	6,733			(23,532		)	(8,557		)
Expenses (1)	290,751			367,633			319,140			147,171
Other expense	5,599			6,665			5,786			2,180
Loss before income taxes	(228,619		)	(275,319		)	(246,366		)	(76,588		)
Income tax provision (benefit)	1,677			(33,305		)	(89,350		)	(26,390		)
Net loss	(230,296		)	(242,014		)	(157,016		)	(50,198		)
Net income attributable to non-controlling interest in subsidiaries	(105		)	(45		)	(75		)	(36		)
Net loss attributable to Matador Resources Company shareholders	$	(230,401	)	$	(242,059	)	$	(157,091	)	$	(50,234	)
Loss per common share attributable to Matador Resources Company shareholders
Basic	$	(2.72	)	$	(2.86	)	$	(1.89	)	$	(0.68	)
Diluted	$	(2.72	)	$	(2.86	)	$	(1.89	)	$	(0.68	)

__________________

(1) Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million, $285.7 million, $229.0 million and $67.1 million, respectively.

48

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	Matador Resources Co
Entity Central Index Key	0001520006
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Deferred gain on sale of property, current	$ 0	$ 4,830
Current assets
Cash	212,884	16,732
Restricted cash	1,258	44,357
Accounts receivable
Oil and natural gas revenues	34,154	16,616
Joint interest billings	19,347	16,999
Other	5,167	10,794
Derivative instruments	0	16,284
Lease and well equipment inventory	3,045	2,022
Prepaid expenses and other assets	3,327	3,203
Total current assets	279,182	127,007
Oil and natural gas properties, full-cost method
Evaluated	2,408,305	2,122,174
Unproved and unevaluated	479,736	387,504
Other property and equipment	160,795	86,387
Less accumulated depletion, depreciation and amortization	(1,864,311)	(1,583,659)
Net property and equipment	1,184,525	1,012,406
Other assets
Other assets	958	1,448
Total assets	1,464,665	1,140,861
Current liabilities
Accounts payable	4,674	10,966
Accrued liabilities	101,460	92,369
Royalties payable	23,988	16,493
Amounts due to affiliates	8,651	5,670
Derivative instruments	24,203	0
Advances from joint interest owners	1,700	700
Amounts due to joint ventures	4,251	2,793
Income taxes payable	0	2,848
Other current liabilities	578	161
Total current liabilities	169,505	136,830
Long-term liabilities
Borrowings under Credit Agreement	0
Senior unsecured notes payable	573,924	391,254
Asset retirement obligations	19,725	15,166
Derivative instruments	751	0
Amounts due to joint ventures	1,771	3,956
Deferred gain on sale of property, non-current	0	102,506
Other long-term liabilities	7,544	2,190
Total long-term liabilities	603,715	515,072
Commitments and contingencies (Note 13)
Shareholders' equity
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995	856
Additional paid-in capital	1,325,481	1,026,077
Accumulated deficit	(636,351)	(538,930)
Total shareholders' equity	690,125	488,003
Non-controlling interest in subsidiaries	1,320	956
Total shareholders’ equity	691,445	488,959
Total liabilities and shareholders’ equity	$ 1,464,665	$ 1,140,861

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	99,517,764	85,567,021
Common stock, shares outstanding	99,512,886	85,564,435

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Oil and natural gas revenues	$ 291,156	$ 278,340	$ 367,712
Midstream services revenues	5,218	1,864	1,213
Third-party midstream services revenues	9,286	77,094	5,022
Unrealized (loss) gain on derivatives	(41,238)	(39,265)	58,302
Total revenues	264,422	318,033	432,249
Expenses
Production taxes and marketing	43,046	35,650	33,172
Lease operating	56,202	54,704	49,945
Plant and other midstream services operating	5,389	3,489	1,408
Depletion, depreciation and amortization	122,048	178,847	134,737
Accretion of asset retirement obligations	1,182	734	504
Full-cost ceiling impairment	158,633	801,166	0
General and administrative	55,089	50,105	32,152
Total expenses	441,589	1,124,695	251,918
Operating (loss) income	(177,167)	(806,662)	180,331
Other income (expense)
Net gain on asset sales and inventory impairment	107,277	908	0
Interest expense	(28,199)	(21,754)	(5,334)
Interest and Other Income (Expense)	(4)	616	132
Total other income (expense)	79,074	(20,230)	(5,202)
(Loss) income before income taxes	(98,093)	(826,892)	175,129
Income tax provision (benefit)
Current	(1,036)	2,959	133
Deferred	0	(150,327)	64,242
Total income tax (benefit) provision	(1,036)	(147,368)	64,375
Net (loss) income	(97,057)	(679,524)	110,754
Net (income) loss attributable to non-controlling interest in subsidiaries	(364)	(261)	17
Net (loss) income attributable to Matador Resources Company shareholders	$ (97,421)	$ (679,785)	$ 110,771
Earnings (loss) per common share
Basic (usd per share)	$ (1.07)	$ (8.34)	$ 1.58
Diluted (usd per share)	$ (1.07)	$ (8.34)	$ 1.56
Weighted average common shares outstanding
Basic	91,273	81,537	70,229
Diluted	91,273	81,537	70,906

XML

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Total	Common stock	Preferred Stock	Additional paid-in capital	Retained earnings (deficit)	Treasury stock	Parent	Noncontrolling Interest	Common Class A [Member] Common stock	Convertible Preferred Stock [Member]	Convertible Preferred Stock [Member] Common stock	Convertible Preferred Stock [Member] Preferred Stock	Convertible Preferred Stock [Member] Additional paid-in capital	Convertible Preferred Stock [Member] Parent
Beginning Balance at Dec. 31, 2013	$ 568,924,000	$ 670,000	$ 0	$ 548,935,000	$ 30,084,000	$ (10,765,000)	$ 568,924,000
Beginning Balance, shares at Dec. 31, 2013		66,959,000	0			1,306,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	181,875,000	$ 75,000		181,800,000			181,875,000
Issuance of Class A common stock, shares		7,500,000
Issuance of Class A common stock to Board member and advisors	16,000	$ 0		16,000			16,000
Issuance of Class A common stock to Board member and advisors, shares		30,000
Stock options expense related to equity based awards	2,279,000			2,279,000			2,279,000
Stock options exercised, shares									8,000
Stock options exercised	43,000			43,000			43,000		$ 0
Liability-based stock option awards settled	84,000			84,000			84,000
Restricted stock issued	0	$ (2,000)		(2,000)			0
Restricted stock issued, shares		212,000
Restricted stock forfeited	(17,000)			(17,000)			(17,000)
Restricted stock forfeited, Shares						60,000
Restricted stock and restricted stock units expense	3,023,000			3,023,000			3,023,000
Cancellation of treasury stock		$ (13,000)		(10,752,000)		$ 10,765,000
Proceeds from issuance of senior unsecured notes	0						0
Cancellation of treasury stock (shares)		1,335,000				1,335,000
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	150,000							$ 150,000
Class B dividends declared	(150,000)				0		0
Net (loss) income	110,754,000				110,771,000		110,771,000	(17,000)
Cost to issue equity	(590,000)			(590,000)			(590,000)
Ending Balance, shares at Dec. 31, 2014		73,374,000	0			31,000
Ending Balance at Dec. 31, 2014	866,541,000	$ 734,000	$ 0	724,819,000	140,855,000	$ 0	866,408,000	133,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	260,252,000	$ 104,000		260,148,000			260,252,000			$ 32,490,000		$ 1,000	$ 32,489,000	$ 32,490,000
Issuance of Class A common stock, shares		10,329,000										150,000
Conversion of Class B common stock to Class A common stock, shares		(1,500,000)	150,000
Stock Issued During Period, Value, Conversion of Convertible Securities	0	$ (15,000)	$ 1,000	14,000			0
Stock options expense related to equity based awards	9,333,000			9,333,000			9,333,000
Stock options exercised, shares		25,000
Stock options exercised	10,000			10,000			10,000
Liability-based stock option awards settled, shares		25,000
Liability-based stock option awards settled	446,000			446,000			446,000
Restricted stock issued	0	$ (4,000)		(4,000)			0
Restricted stock issued, shares		429,000
Restricted stock forfeited	0			0			0
Restricted stock forfeited, Shares						138,000
Vesting of restricted stock units		52,000
Restricted stock and restricted stock units expense	0	$ 1,000		(1,000)			0
Cancellation of treasury stock	0	$ 2,000		2,000		$ 0	0
Proceeds from issuance of senior unsecured notes	400,000,000
Cancellation of treasury stock (shares)		(167,000)				(167,000)
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	562,000							562,000
Class B dividends declared					0
Net (loss) income	(679,524,000)				(679,785,000)		(679,785,000)	261,000
Cost to issue equity	$ (1,151,000)	$ 0		(1,151,000)			(1,151,000)
Ending Balance, shares at Dec. 31, 2015	85,564,435	85,567,000	0			2,000
Ending Balance at Dec. 31, 2015	$ 488,959,000	$ 856,000	$ 0	1,026,077,000	(538,930,000)	$ 0	488,003,000	956,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Class A common stock	288,510,000	$ 135,000		288,375,000			288,510,000			0	$ 4,000	$ 0	(4,000)	0
Issuance of Class A common stock, shares		13,500,000									471,000	0
Issuance of Class A common stock to Board member and advisors		$ 1,000								$ 0			$ (1,000)	$ 0
Issuance of Class A common stock to Board member and advisors, shares		51,000
Stock options expense related to equity based awards	$ 11,958,000			11,958,000			11,958,000
Stock options exercised, shares	114,000	36,000
Stock options exercised	$ 10,000			10,000			10,000
Liability-based stock option awards settled, shares		10,000
Liability-based stock option awards settled	255,000			255,000			255,000
Restricted stock forfeited	0			0			0
Restricted stock forfeited, Shares						120,000
Cancellation of treasury stock	0	$ 1,000		1,000		$ 0	0
Proceeds from issuance of senior unsecured notes	184,625,000
Cancellation of treasury stock (shares)		(116,000)				(116,000)
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	0
Net (loss) income	(97,057,000)				(97,421,000)		(97,421,000)	364,000
Cost to issue equity	$ (1,190,000)			(1,190,000)			(1,190,000)
Ending Balance, shares at Dec. 31, 2016	99,512,886	99,519,000	0			6,000
Ending Balance at Dec. 31, 2016	$ 691,445,000	$ 995,000	$ 0	$ 1,325,481,000	$ (636,351,000)	$ 0	$ 690,125,000	$ 1,320,000

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net (loss) income	$ (97,057)	$ (679,524)	$ 110,754
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Unrealized (loss) gain on derivatives	41,238	39,265	(58,302)
Depletion, depreciation and amortization	122,048	178,847	134,737
Accretion of asset retirement obligations	1,182	734	504
Full-cost ceiling impairment	158,633	801,166	0
Stock-based compensation expense	12,362	9,450	5,524
Deferred income tax (benefit) provision	0	(150,327)	64,242
Amortization of debt issuance cost	1,148	852	0
Net gain on asset sales and inventory impairment	(107,277)	(908)	0
Changes in operating assets and liabilities
Accounts receivable	(14,259)	3,633	(13,318)
Lease and well equipment inventory	(700)	(180)	(211)
Prepaid expenses	(124)	(544)	(783)
Other assets	490	(552)	1,212
Accounts payable, accrued liabilities and other current liabilities	6,611	1,375	607
Royalties payable	7,495	1,654	6,663
Advances from joint interest owners	1,000	700	0
Income taxes payable	(2,848)	2,405	39
Other long-term liabilities	4,144	489	(187)
Net cash provided by operating activities	134,086	208,535	251,481
Investing activities
Proceeds from sale of assets	5,173	139,836	79
Oil and natural gas properties capital expenditures	(379,067)	(432,715)	(560,849)
Expenditures for other property and equipment	(74,845)	(64,499)	(9,152)
Business combination, net of cash acquired	0	(24,028)	0
Restricted cash	43,098	(43,098)	0
Restricted cash in less-than-wholly-owned subsidiaries	1	(650)	(609)
Net cash used in investing activities	(405,640)	(425,154)	(570,531)
Financing activities
Repayments of borrowings	(120,000)	(476,982)	(180,000)
Borrowings under Credit Agreement	120,000	125,000	320,000
Proceeds from issuance of common stock	288,510	188,720	181,875
Proceeds from issuance of senior unsecured notes	184,625	400,000	0
Cost to issue equity	(847)	(1,158)	(590)
Cost to issue senior unsecured notes	(2,734)	(9,598)	0
Proceeds from stock options exercised	100	10	43
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries	0	562	150
Taxes paid related to net share settlement of stock-based compensation	(1,948)	(1,610)	(308)
Net cash provided by financing activities	467,706	224,944	321,170
Increase in cash	196,152	8,325	2,120
Cash at beginning of year	16,732	8,407	6,287
Cash at end of year	$ 212,884	$ 16,732	$ 8,407

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Nature of Operations

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF OPERATIONS

NATURE OF OPERATIONS

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

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company 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. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting at December 31, 2016. As a result, $1.8 million and $1.2 million for the years ended December 31, 2015 and 2014, respectively, were reclassified from other income to third-party midstream services revenues. In addition, $3.5 million and $1.4 million related to midstream operating costs for the years ended December 31, 2015 and 2014, respectively, were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Change in Accounting Principles

During the second quarter of 2016, the Company adopted Accounting Standards Update (“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, requiring either retrospective, modified retrospective or prospective transition. The amended guidance also requires an entity to record excess tax benefits and deficiencies in the income statement. The adoption of this ASU had no impact on any period presented for (i) the Company’s financial position or statements of operations, as the Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of cash flows, as the Company has historically accounted for taxes paid for net share settlement as a financing activity as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of this ASU.

Use of Estimates

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, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations 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. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Restricted Cash

Restricted cash represents a portion of the cash paid for the Loving County Processing System by EnLink (as described in Note 5) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to the Company by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $15.7 million, $6.9 million and $6.4 million of its general and administrative costs in 2016, 2015 and 2014, respectively. The Company capitalized $3.7 million, $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2014, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014.

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 sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s 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.

Other Property and Equipment

Other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using 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. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments.

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable.

For the year ended December 31, 2016, three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). For the year ended December 31, 2015, three significant purchasers accounted for 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (33%), Enterprise Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). For the year ended December 31, 2014, three significant purchasers accounted for approximately 68% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (45%), Enterprise Crude Oil LLC (12%) and Enterprise Products Operating LLC (11%). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2016, 2015 and 2014, approximately 38%, 39% and 44%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 include a stock-based compensation (non-cash) expense of $12.4 million, $9.5 million and $5.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.0 million, $0.9 million and $0.3 million in 2016, 2015 and 2014, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2016, 2015 and 2014, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2016, 2015 and 2014.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

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 (loss) per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share data).

	Year Ended December 31,
	2016			2015			2014
Net (loss) income attributable to Matador Resources Company shareholders — numerator	$	(97,421	)	$	(679,785	)	$	110,771
Weighted average common shares outstanding — denominator
Basic	91,273			81,537			70,229
Dilutive effect of options, restricted stock units and preferred shares	—			—			677
Diluted weighted average common shares outstanding	91,273			81,537			70,906
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	(1.07	)	$	(8.34	)	$	1.58
Diluted	$	(1.07	)	$	(8.34	)	$	1.56

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company.

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2016 were with Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s Credit Agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

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

Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

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

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

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

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Property and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2016 and 2015 (in thousands).

	December 31,
	2016			2015
Oil and natural gas properties
Evaluated (subject to amortization)	$	2,408,305		$	2,122,174
Unproved and unevaluated (not subject to amortization)	479,736			387,504
Total oil and natural gas properties	2,888,041			2,509,678
Accumulated depletion	(1,850,882		)	(1,574,040		)
Net oil and natural gas properties	1,037,159			935,638
Other property and equipment
Midstream equipment and facilities	145,662			78,564
Furniture, fixtures and other equipment	5,487			2,918
Software	3,206			2,193
Land	1,437			1,539
Leasehold improvements	5,003			1,173
Total other property and equipment	160,795			86,387
Accumulated depreciation	(13,429		)	(9,619		)
Net other property and equipment	147,366			76,768
Net property and equipment	$	1,184,525		$	1,012,406

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2016 and the year in which these costs were incurred (in thousands).

Description	2016		2015		2014		2013 and prior		Total
Costs incurred for
Property acquisition	$	126,857	$	236,507	$	55,258	$	23,654	$	442,276
Exploration wells	19,017		3,375		34		—		22,426
Development wells	13,086		1,218		730		—		15,034
Total	$	158,960	$	241,100	$	56,022	$	23,654	$	479,736

Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2016 are related primarily to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past four years. These costs include, in particular, the cost of the acreage acquired as part of the HEYCO Merger (as described and defined in Note 5) in 2015. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties which are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $37.5 million at December 31, 2016. Of this total, $22.4 million was associated with exploration wells and $15.0 million was associated with development wells. The Company anticipates that most of the $37.5 million associated with these wells in progress at December 31, 2016 will be transferred to the amortization base during 2017.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2016 and 2015 (in thousands).

	Year Ended December 31,
	2016			2015
Beginning asset retirement obligations	$	15,420		$	11,951
Liabilities incurred during period	1,791			4,508
Liabilities settled during period	(375		)	(588		)
Revisions in estimated cash flows	2,622			(1,185		)
Accretion expense	1,182			734
Ending asset retirement obligations	20,640			15,420
Less: current asset retirement obligations (1)	(915		)	(254		)
Long-term asset retirement obligations	$	19,725		$	15,166

__________________

(1) Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2016 and 2015.

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Business Combinations and Divestitures (Notes)

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

BUSINESS COMBINATIONS AND DIVESTITURES

Business Combinations

On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross (18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction.

As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Matador incurred an additional $4.5 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing.  The consideration paid and the liabilities assumed, including deferred tax liabilities of approximately $76.8 million and other liabilities of approximately $4.5 million, represent a total purchase price of $223.5 million. The HEYCO Merger was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date.

The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage. The producing wells acquired in the HEYCO Merger did not have a material impact on the Company’s revenues or results of operations for the year ended December 31, 2015. During the year ended December 31, 2015, the Company incurred approximately $2.5 million of transaction costs associated with the HEYCO Merger, which were included in “General and administrative” costs in the consolidated statement of operations.

Divestitures

On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and the Company received net proceeds of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million. In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15-year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement.

Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and processing agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink is now processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink is no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016.

The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017 these assets were contributed to the Joint Venture (as described and defined in Note 18).

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Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

DEBT

DEBT

Credit Agreement

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million. MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company.

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. On October 31, 2016, the borrowing base was increased from $300.0 million to $400.0 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at June 30, 2016 using commodity price estimates prescribed by the lenders. This borrowing base increase was primarily attributable to increases in both the Company’s proved reserves volumes and increases in oil and natural gas prices in the latter part of 2016. All other provisions of the Credit Agreement remained unchanged. This October 2016 redetermination constituted the regularly scheduled November 1 redetermination. The Credit Agreement matures on October 16, 2020.

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 were $1.3 million at December 31, 2016, and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.

During the year ended December 31, 2016, using a portion of the net proceeds from the December 2016 senior unsecured notes offering and the public offering of our common stock discussed herein, the Company repaid a total of $120.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2016, the Company had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. At February 22, 2017, the Company continued to have no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company.

A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:

• incur indebtedness or grant liens on any of the Company’s assets;

• enter into commodity hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with affiliates;

• engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and

• take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;

• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving the Company or its subsidiaries; and

• a change of control, as defined in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2016.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes are Matador’s senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original Notes mature on April 15, 2023 and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On October 21, 2015, and pursuant to a registered exchange offer, the Company exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes.

On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes” and, collectively with the Registered Notes, the “Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5%. We received net proceeds from the Notes Offering of approximately $181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. A portion of the net proceeds of the Notes Offering, along with the proceeds from the December 2016 public offering of our common stock, have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig. The Notes are our senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated.

Year	Redemption Price
2018	105.156%
2019	103.438%
2020	101.719%
2021 and thereafter	100.000%

At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.

In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date.

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:

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

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

• transfer or sell assets;

• make certain investments;

• create certain liens;

• enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company;

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

• engage in transactions with affiliates; and

• create unrestricted subsidiaries.

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:

• default for 30 days in the payment when due of interest on the Notes;

• default in the payment when due of the principal of, or premium, if any, on the Notes;

• failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets;

• failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;

• failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;

• payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more;

• failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days;

• any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and

• certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2016 and 2015, respectively, is as follows (in thousands).

	December 31,
	2016			2015
Deferred tax assets
Unrealized loss on derivatives	$	8,734		$	—
Net operating loss carryforwards	137,757			79,208
Alternative minimum tax carryforward	8,633			9,785
Percentage depletion carryover	2,595			2,442
Property and equipment	44,391			42,757
Deferred gain on sale leaseback transaction	—			32,831
Other	—			7,396
Total deferred tax assets	202,110			174,419
Valuation allowance on deferred tax assets	(190,255		)	(154,320		)
Total deferred tax assets, net of valuation allowance	11,855			20,099
Deferred tax liabilities
Unrealized gain on derivatives	(3,800		)	(5,699		)
Other	(8,055		)	(14,400		)
Total deferred tax liabilities	(11,855		)	(20,099		)
Net deferred tax liabilities	$	—		$	—

At December 31, 2016, the Company had net operating loss carryforwards of $375.9 million for federal income tax purposes and $6.2 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the State of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company recorded an impairment charge of $158.6 million and $801.2 million, respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2016 and 2015, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2015 and 2016. As a result, at December 31, 2016 and 2015, the Company maintained a valuation allowance against the Company’s federal and state deferred tax assets. The valuation allowance will continue to be recognized until the realization of future tax benefits are more likely than not to be utilized.

The current income tax provision for the years ended December 31, 2016, 2015 and 2014, respectively, was comprised of the following (in thousands).

	Year Ended December 31,
	2016			2015		2014
Current income tax provision
State income tax	$	108		$	371	$	—
Federal alternative minimum tax	(1,144		)	2,588		133
Net current income tax (benefit) provision	$	(1,036	)	$	2,959	$	133

Reconciliations of the tax (benefit) expense computed at the statutory federal rate to the Company’s total income tax (benefit) provision for the years ended December 31, 2016, 2015 and 2014, respectively, is as follows (in thousands).

	Year Ended December 31,
	2016			2015			2014
Federal tax (benefit) expense at statutory rate (1)	$	(34,333	)	$	(289,412	)	$	61,301
State income tax	539			(13,215		)	2,707
Permanent differences (2)	(499		)	698			397
Federal alternative minimum tax	1,144			(2,588		)	(133		)
Change in federal valuation allowance	33,688			145,777			—
Change in state valuation allowance	(539		)	8,413			(30		)
Net deferred income tax (benefit) provision	—			(150,327		)	64,242
Net current income tax (benefit) provision	(1,036		)	2,959			133
Total income tax (benefit) provision	$	(1,036	)	$	(147,368	)	$	64,375

__________________    

(1) The statutory federal tax rate was 35% for the years ended December 31, 2016, 2015 and 2014.

(2) Amount is primarily attributable to stock-based compensation.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2012. The earliest tax year open for examination by the State of Texas is 2009. During the year ended December 31, 2016, the Company’s 2009 and 2010 franchise tax returns were under examination by the State of Texas. This examination has been completed with no additional tax due; however, the examination has not been formally closed. In addition, as of December 31, 2016, the Company’s 2013 federal income tax return was under examination by the Internal Revenue Service. This examination has been completed with no additional tax due; however, the examination has not been formally closed.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2016, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2016

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

STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company.

In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2016, the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years.

The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.14 years	0.39 years	1.51 years
Risk-free interest rate	1.70%	0.64%	0.74%
Volatility	47.07%	91.98%	55.14%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.96 years	4.00 years	3.99 years
Risk-free interest rate	1.08%	1.15%	1.21%
Volatility	45.68%	56.89%	51.47%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	1.16%	3.21%	4.28%
Weighted average fair value of stock option awards granted during the year	$5.65	$9.90	$9.45

The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2016 under the 2003 Plan and the 2012 Incentive Plan is as follows.

	Number of options (in thousands)		Weighted average exercise price
Options outstanding at December 31, 2015	2,363		$	15.40
Options granted	668		$	15.51
Options exercised	(114	)	$	10.12
Options forfeited	(28	)	$	19.73
Options expired	(2	)	$	22.66
Options outstanding at December 31, 2016	2,887		$	15.59

	Options outstanding at December 31, 2016				Options exercisable at December 31, 2016
Range of exercise prices	Shares outstanding (in thousands)	Weighted average remaining contractual life	Weighted average exercise price		Shares exercisable (in thousands)	Weighted average exercise price
$8.18 - $9.55	816	1.30	$	8.30	484	$	8.35
$10.49 - $17.80	925	2.87	$	13.55	302	$	10.58
$18.77 - $22.70	862	3.05	$	21.84	65	$	21.21
$23.40 - $27.33	284	2.26	$	24.22	112	$	23.49

At December 31, 2016, the aggregate intrinsic value was $29.4 million for outstanding options and $13.6 million for exercisable options, based on the Company’s quoted closing market price of $25.76 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2016 was 1.19 years.

The total intrinsic value of options exercised during the years ended December 31, 2016, 2015 and 2014 was $1.6 million, $1.3 million and $0.2 million, respectively. The tax related benefit realized from the exercise of stock options totaled $0.5 million, $0.3 million and $0.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

During the years ended December 31, 2016, 2015 and 2014, the Company recognized $5.9 million, $4.7 million and $2.5 million, respectively, in stock-based compensation expense attributable to stock options. At December 31, 2016, 2015 and 2014, the Company had recorded $1.4 million, zero and $1.4 million of long-term liabilities and zero, $1.0 million and zero of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2016, 2015 and 2014, respectively.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested stock options was approximately $6.9 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.90 years.

The fair value of options vested during 2016, 2015 and 2014 was $3.0 million, $1.3 million and $1.5 million, respectively.

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. One current director elected to defer the issuance of his awards in 2015, 2014 and 2013. All awards granted in 2016, 2015 and 2014 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2016 were granted under the 2012 Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2016 is presented below (in thousands, except fair value).

	Restricted Stock				Restricted Stock Units
Non-vested restricted stock and restricted stock units	Shares		Weighted average fair value		Shares		Weighted average fair value
Non-vested at December 31, 2015	854		$	17.64	68		$	21.89
Granted	472		$	18.55	66		$	19.44
Vested	(225	)	$	16.05	(52	)	$	19.67
Forfeited	(62	)	$	20.49	—		—
Non-vested at December 31, 2016	1,039		$	18.23	82		$	21.32

At December 31, 2016, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $28.9 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $25.76 per share on that date.

During the years ended December 31, 2016, 2015 and 2014, the Company recognized approximately $6.6 million, $4.7 million and $3.0 million, respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $12.5 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.8 years.

The fair value of restricted stock and restricted stock units vested during 2016, 2015 and 2014 was $4.6 million, $0.8 million and $0.9 million, respectively.

The total tax benefit recognized for all stock-based compensation was $4.3 million, $3.4 million and $1.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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

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

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled approximately $0.7 million, $0.6 million and $0.4 million in 2016, 2015 and 2014, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $0.9 million, $0.8 million and $0.5 million in 2016, 2015 and 2014, respectively. The Company made no additional discretionary contributions in any reporting period presented.

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Equity

12 Months Ended

Dec. 31, 2016

Stockholders' Equity Note [Abstract]

EQUITY

Stock Offerings, Retirement and Issuances

On December 9, 2016, the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million, the Company received net proceeds of approximately $145.8 million. A portion of the net proceeds of the public offering, along with the proceeds from the Notes Offering (see Note 6), have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig.

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 were used for general corporate purposes, including to fund a portion of the Company’s 2016 capital expenditures.

As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock.

On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2016 to satisfy certain conditions under the merger agreement.

On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million, the Company received net proceeds of approximately $187.6 million.

On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million, the Company received net proceeds of approximately $181.3 million.

Treasury Stock

On October 27, 2016, October 30, 2015 and October 31, 2014, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2016, September 30, 2015 and September 30, 2014, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2016, 2015 and 2014 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees.

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using 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. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments.

The Company typically uses 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 the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.

At December 31, 2016, we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period.

When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume

At December 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 2017 and 2018.

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

		Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Liabilities (thousands)
Commodity	Calculation Period
Oil	01/01/2017 - 12/31/2017	2,760,000	$	41.39	$	51.88	$	(18,316	)
Oil	01/01/2018 - 12/31/2018	720,000	$	43.75	$	63.90	(751		)
Natural Gas	01/01/2017 - 12/31/2017	16,860,000	$	2.40	$	3.59	(5,887		)
Total open derivative financial instruments							$	(24,954	)

Subsequent to December 31, 2016, the Company entered into various costless collar contracts for oil. The costless collar contracts for oil included approximately 1,890,000 Bbl in 2017 with a weighted average floor price of $50.00 per Bbl and a weighted average ceiling price of $60.75 per Bbl.

From time-to-time we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlements 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 consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2016 and December 31, 2015 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)
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 consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.

		Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2016			2015			2014
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	5,851		$	62,259		$	5,221
Natural Gas	Revenues: Realized gain (loss) on derivatives	3,435			12,653			(718		)
Natural Gas Liquids (NGL)	Revenues: Realized gain on derivatives	—			2,182			519
Realized gain on derivatives		9,286			77,094			5,022
Oil	Revenues: Unrealized (loss) gain on derivatives	(18,969		)	(31,897		)	47,178
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(22,269		)	(5,440		)	9,087
Natural Gas Liquids (NGL)	Revenues: Unrealized (loss) gain on derivatives	—			(1,928		)	2,037
Unrealized (loss) gain on derivatives		(41,238		)	(39,265		)	58,302
Total		$	(31,952	)	$	37,829		$	63,324

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Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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

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

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

Level 3 Unobservable inputs that are not corroborated by market data 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.

At December 31, 2016 and 2015, the carrying values reported on the 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 approximate their fair values due to their short-term maturities.

At December 31, 2016 and 2015, the fair value of the Company’s Notes was $605.2 million and $381.0 million, respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy.

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 December 31, 2016 and 2015 (in thousands).

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

	Fair Value Measurements at December 31, 2015 using
Description
	Level 1		Level 2		Level 3		Total
Assets (Liabilities)
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 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy.

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination (see Note 5), lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2016 and 2015. The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026. The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease.

From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties.

The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2016 (in thousands).

Year Ending December 31,	Amount
2017	$	2,443
2018	2,495
2019	2,528
2020	2,602
2021	2,660
Thereafter	12,335
Total	$	25,063

Rent expense, including fees for operating expenses and consumption of electricity, was $2.9 million, $1.7 million, and $0.9 million for 2016, 2015 and 2014, respectively.

Natural Gas and NGL Processing and Transportation Commitments

Eagle Ford

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

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid approximately $3.0 million and $5.5 million in processing and transportation fees under this agreement during the years ended December 31, 2016 and 2015, respectively. The future undiscounted minimum payment under this agreement as of December 31, 2016 is $1.2 millionin 2017.

Delaware Basin

As part of the sale of the Loving County Processing System (see Note 5), the Company entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2016, the total deficiency fee required to be paid would be approximately $11.7 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 $9.8 million and $1.8 million in processing and gathering fees under this agreement during the years ended December 31, 2016 and 2015, respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for two years or less. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $46.3 million at December 31, 2016.

At December 31, 2016, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $11.1 million at December 31, 2016. The Company expects these costs to be incurred within the next year.

Legal Proceedings

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

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Supplemental Disclosures

12 Months Ended

Dec. 31, 2016

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

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

	December 31,
	2016		2015
Accrued evaluated and unproved and unevaluated property costs	$	54,273	$	54,586
Accrued support equipment and facilities costs	15,139		17,393
Accrued lease operating expenses	16,009		7,743
Accrued interest on debt	6,541		5,806
Accrued asset retirement obligations	915		254
Accrued partners’ share of joint interest charges	5,572		4,565
Other	3,011		2,022
Total accrued liabilities	$	101,460	$	92,369

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Cash paid for income taxes	$	2,895		$	506		$	94
Cash paid for interest expense, net of amounts capitalized	27,464			16,154			5,269
Increase in asset retirement obligations related to mineral properties	3,817			2,510			3,843
Increase in asset retirement obligations related to support equipment and facilities	222			383			120
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	1,775			(30,683		)	32,972
(Decrease) increase in liabilities for support equipment and facilities	(588		)	12,076			4,290
Issuance of restricted stock units for Board and advisor services	992			584			444
Stock-based compensation expense recognized as liability	569			79			223
Increase in liabilities for accrued cost to issue equity	343			—			—
Transfer of inventory to oil and natural gas properties	395			615			216

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Subsidiary Guarantors (Notes)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

SUBSIDIARY GUARANTORS

SUBSIDIARY GUARANTORS

Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the Company issued the Original Notes and on December 9, 2016, the Company issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries” and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2016, the Guarantor Subsidiaries were 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries were 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.

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Related Party Transactions (Notes)

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2016, the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities.

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Segment Reporting (Notes)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Segment Reporting

SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During the third quarter of 2016, our midstream business became a reportable segment under U.S. GAAP. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

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

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2016
Oil and natural gas revenues	$	289,512		$	1,644	$	—		$	—		$	291,156
Midstream services revenues	—			18,982		—			(13,764		)	5,218
Realized gain on derivatives	9,286			—		—			—			9,286
Unrealized gain on derivatives	(41,238		)	—		—			—			(41,238		)
Expenses (1)	391,098			8,254		56,001			(13,764		)	441,589
Operating (loss) income (2)	$	(133,538	)	$	12,372	$	(56,001	)	$	—		$	(177,167	)
Total Assets	$	1,098,525		$	140,459	$	225,681		$	—		$	1,464,665
Capital Expenditures	$	379,881		$	67,566	$	6,913		$	—		$	454,360

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $118.4 million, $2.7 million and $0.9 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.

(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2015
Oil and natural gas revenues	$	277,844		$	496	$	—		$	—		$	278,340
Midstream services revenues	—			11,485		—			(9,621		)	1,864
Realized gain on derivatives	77,094			—		—			—			77,094
Unrealized loss on derivatives	(39,265		)	—		—			—			(39,265		)
Expenses (1)	1,078,534			5,178		50,604			(9,621		)	1,124,695
Operating (loss) income (2)	$	(762,861	)	$	6,803	$	(50,604	)	$	—		$	(806,662	)
Total Assets	$	1,000,075		$	75,980	$	64,806		$	—		$	1,140,861
Capital Expenditures (3)	$	622,642		$	75,009	$	786		$	—		$	698,437

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $176.7 million, $1.6 million and $0.5 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment.

(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) In October 2015, the Company sold the Wolf Processing Plant to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets.

	Exploration and Production										Consolidated Company
			Midstream		Corporate			Eliminations
Year Ended December 31, 2014
Oil and natural gas revenues	$	366,191	$	1,521	$	—		$	—		$	367,712
Midstream services revenues	—		4,929		—			(3,716		)	1,213
Realized gain on derivatives	5,022		—		—			—			5,022
Unrealized loss on derivatives	58,302		—		—			—			58,302
Expenses (1)	220,374		2,703		32,557			(3,716		)	251,918
Operating (loss) income (2)	$	209,141	$	3,747	$	(32,557	)	$	—		$	180,331
Total Assets	$	1,388,261	$	35,100	$	11,129		$	—		$	1,434,490
Capital Expenditures	$	597,351	$	12,504	$	517		$	—		$	610,372

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $133.1 million, $1.2 million and $0.4 million for the exploration and production, midstream and corporate segments, respectively.

(2) Includes $17,000 in net loss attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Subsequent Events

12 Months Ended

Dec. 31, 2016

Subsequent Events [Abstract]

Subsequent Events

Subsequent to December 31, 2016, the Company acquired approximately 13,900 gross (8,200 net) leased and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around its existing acreage in the Delaware Basin. The cost of these acquisitions was approximately $111 million.

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

The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution. The Company may earn an additional $73.5 million in performance incentives over the next five years. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140 million in the aggregate to expand the Joint Venture’s midstream operations and asset base.

In connection with the Joint Venture, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed fee natural gas processing agreement (when combined with the gathering and salt water disposal agreements, the “Operational Agreements”). The Joint Venture will provide the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at inception was approximately $273.5 million.

The following unaudited pro forma consolidated financial information is presented to illustrate the effect on the historical operating results and financial position of the Company of (a) the formation of San Mateo and the transactions associated with the Joint Venture and (b) the Company’s acquisition on February 14, 2017 of the remaining non-controlling interest in Fulcrum Delaware Water Resources, LLC (“Fulcrum Delaware Water Resources”) not previously owned by the Company for approximately $2.6 million (collectively, the “Transactions”).

The Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2016, if presented, would contain an adjustment of $4.5 million to increase the net income attributable to non-controlling interest in subsidiaries from $0.4 million to $4.9 million, which would increase the net loss attributable to Matador Resources Company shareholders from $97.4 million to $102.0 million, and an adjustment of $0.05 per diluted common share to increase the net loss per diluted common share attributable to Matador Resources Company shareholders from $1.07 to $1.12.

The following Unaudited Pro Forma Consolidated Balance Sheet as of December 31, 2016, presented for illustrative purposes, is based on the historical financial statements of the Company as of December 31, 2016, after giving effect to the Transactions as if they had occurred on December 31, 2016.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

	December 31, 2016
	As Reported			Adjustment			Pro Forma
ASSETS
Current assets
Cash	$	212,884		$	164,340	(1)	$	377,224
Restricted cash	1,258			9,407		(2)	10,665
Accounts receivable							—
Oil and natural gas revenues	34,154			—			34,154
Joint interest billings	19,347			—			19,347
Other	5,167			—			5,167
Lease and well equipment inventory	3,045			—			3,045
Prepaid expenses and other assets	3,327			—			3,327
Total current assets	279,182			173,747			452,929
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,408,305			—			2,408,305
Unproved and unevaluated	479,736			—			479,736
Other property and equipment	160,795			—			160,795
Less accumulated depletion, depreciation and amortization	(1,864,311		)	—			(1,864,311		)
Net property and equipment	1,184,525			—			1,184,525
Other assets	958						958
Total assets	$	1,464,665		$	173,747		$	1,638,412
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	4,674		$	—		$	4,674
Accrued liabilities	101,460			—			101,460
Royalties payable	23,988			—			23,988
Amounts due to affiliates	8,651			—			8,651
Derivative instruments	24,203			—			24,203
Advances from joint interest owners	1,700			—			1,700
Amounts due to joint ventures	4,251			—			4,251
Other current liabilities	578			—			578
Total current liabilities	169,505			—			169,505
Long-term liabilities
Senior unsecured notes payable	573,924			—			573,924
Asset retirement obligations	19,725			—			19,725
Derivative instruments	751			—			751
Amounts due to joint ventures	1,771			—			1,771
Other long-term liabilities	7,544			—			7,544
Total long-term liabilities	603,715			—			603,715
Commitments and contingencies (Note 13)
Shareholders’ equity
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995			—			995
Additional paid-in capital	1,325,481			124,871		(3)	1,450,352
Accumulated deficit	(636,351		)	—			(636,351		)
Total Matador Resources Company shareholders’ equity	690,125			124,871			814,996
Non-controlling interest in subsidiaries	1,320			48,876		(4)	50,196
Total shareholders’ equity	691,445			173,747			865,192
Total liabilities and shareholders’ equity	$	1,464,665		$	173,747		$	1,638,412

______________________

(1) Represents $176.4 million of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately $2.6 million paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and (ii) $10.0 million of cash restricted to operations of San Mateo. Also reflects $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources not previously owned by the Company.

(2) Represents $10.0 million in cash contributed to San Mateo less $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own.

(3) Reflects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the amount received in connection with the formation of San Mateo.

(4) Represents the adjustment required to reflect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and Five Point’s 49% non-controlling interest in San Mateo.

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Condensed Consolidated Statements (Notes)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidated Financial Statements

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

Condensed Consolidating Balance Sheet December 31, 2015
	Matador		Non-Guarantor Subsidiaries		Existing Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	304,573	$	1,463	$	11,928	$	(317,964	)	$	—
Other current assets	289		1,141		125,577		—			127,007
Net property and equipment	—		47,535		964,871		—			1,012,406
Investment in subsidiaries	584,461		—		20,355		(604,816		)	—
Other long-term assets	—		—		1,448		—			1,448
Total assets	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	$	1,140,861
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	11,928	$	306,036	$	(317,964	)	$	—
Other current liabilities	10,066		16,557		110,207		—			136,830
Senior unsecured notes payable	391,254		—		—		—			391,254
Other long-term liabilities	—		343		123,475		—			123,818
Total equity attributable to Matador Resources Company	488,003		20,355		584,461		(604,816		)	488,003
Non-controlling interest in subsidiaries	—		956		—		—			956
Total liabilities and equity	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	1,140,861

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	17,302		$	257,828		$	(10,708	)	$	264,422
Total expenses	5,319			7,031			439,947			(10,708		)	441,589
Operating (loss) income	(5,319		)	10,271			(182,119		)	—			(177,167		)
Net gain on asset sales and inventory impairment	—			—			107,277			—			107,277
Interest expense	(28,199		)	—			—			—			(28,199		)
Other expense	—			—			(4		)	—			(4		)
(Loss) earnings in subsidiaries	(64,349		)	—			9,810			54,539			—
(Loss) income before income taxes	(97,867		)	10,271			(65,036		)	54,539			(98,093		)
Total income tax (benefit) provision	(446		)	97			(687		)	—			(1,036		)
Net income attributable to non-controlling interest in subsidiaries	—			(364		)	—			—			(364		)
Net (loss) income attributable to Matador Resources Company	$	(97,421	)	$	9,810		$	(64,349	)	$	54,539		$	(97,421	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	6,310		$	316,067		$	(4,344	)	$	318,033
Total expenses	5,739			2,944			1,120,356			(4,344		)	1,124,695
Operating (loss) income	(5,739		)	3,366			(804,289		)	—			(806,662		)
Net gain on asset sales and inventory impairment	—			—			908			—			908
Interest expense	(20,511		)	—			(1,243		)	—			(21,754		)
Other income	—			—			616			—			616
(Loss) earnings in subsidiaries	(658,698		)	—			2,458			656,240			—
(Loss) income before income taxes	(684,948		)	3,366			(801,550		)	656,240			(826,892		)
Total income tax (benefit) provision	(5,163		)	647			(142,852		)	—			(147,368		)
Net income attributable to non-controlling interest in subsidiaries	—			(261		)	—			—			(261		)
Net (loss) income attributable to Matador Resources Company	$	(679,785	)	$	2,458		$	(658,698	)	$	656,240		$	(679,785	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	—		$	432,249		$	—		$	432,249
Total expenses	3,389			111			248,418			—			251,918
Operating (loss) income	(3,389		)	(111		)	183,831			—			180,331
Net gain on asset sales and inventory impairment	—			—			—			—			—
Interest expense	—			—			(5,334		)	—			(5,334		)
Other income	—			—			132			—			132
Earnings (loss) in subsidiaries	112,908			—			(94		)	(112,814		)	—
Income (loss) before income taxes	109,519			(111		)	178,535			(112,814		)	175,129
Total income tax (benefit) provision	(1,252		)	—			65,627			—			64,375
Net loss attributable to non-controlling interest in subsidiaries	—			17			—			—			17
Net income (loss) attributable to Matador Resources Company	$	110,771		$	(94	)	$	112,908		$	(112,814	)	$	110,771

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(45,215	)	$	6,694		$	172,607		$	—		$	134,086
Net cash used in investing activities	(324,724		)	(64,683		)	(401,034		)	384,801			(405,640		)
Net cash provided by financing activities	469,654			60,110			322,743			(384,801		)	467,706
Increase in cash	99,715			2,121			94,316			—			196,152
Cash at beginning of year	80			186			16,466			—			16,732
Cash at end of year	$	99,795		$	2,307		$	110,782		$	—		$	212,884

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(31,271	)	$	13,916		$	225,890		$	—		$	208,535
Net cash used in investing activities	(546,715		)	(31,101		)	(410,843		)	563,505			(425,154		)
Net cash provided by financing activities	577,973			17,353			193,123			(563,505		)	224,944
Increase in cash	(13		)	168			8,170			—			8,325
Cash at beginning of year	93			18			8,296			—			8,407
Cash at end of year	$	80		$	186		$	16,466		$	—		$	16,732

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(8,607	)	$	431		$	259,657		$	—		$	251,481
Net cash used in investing activities	(172,749		)	(1,763		)	(569,968		)	173,949			(570,531		)
Net cash provided by financing activities	181,328			1,350			312,441			(173,949		)	321,170
Increase in cash	(28		)	18			2,130			—			2,120
Cash at beginning of year	121			—			6,166			—			6,287
Cash at end of year	$	93		$	18		$	8,296		$	—		$	8,407

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company 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. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Reclassifications

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting at December 31, 2016. As a result, $1.8 million and $1.2 million for the years ended December 31, 2015 and 2014, respectively, were reclassified from other income to third-party midstream services revenues. In addition, $3.5 million and $1.4 million related to midstream operating costs for the years ended December 31, 2015 and 2014, respectively, were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Use of Estimates

Use of Estimates

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, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations 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. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Restricted Cash

Restricted Cash

Restricted cash represents a portion of the cash paid for the Loving County Processing System by EnLink (as described in Note 5) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to the Company by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $15.7 million, $6.9 million and $6.4 million of its general and administrative costs in 2016, 2015 and 2014, respectively. The Company capitalized $3.7 million, $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2014, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014.

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 sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s 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.

Other Property and Equipment

Other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of other property and equipment

Asset Retirement Obligations

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using 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. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments.

Revenue Recognition

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable.

For the year ended December 31, 2016, three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). For the year ended December 31, 2015, three significant purchasers accounted for 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (33%), Enterprise Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). For the year ended December 31, 2014, three significant purchasers accounted for approximately 68% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company (45%), Enterprise Crude Oil LLC (12%) and Enterprise Products Operating LLC (11%). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2016, 2015 and 2014, approximately 38%, 39% and 44%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

Stock-Based Compensation

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 include a stock-based compensation (non-cash) expense of $12.4 million, $9.5 million and $5.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.0 million, $0.9 million and $0.3 million in 2016, 2015 and 2014, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2016, 2015 and 2014, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2016, 2015 and 2014.

Earnings Per Common Share

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 (loss) per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share data).

	Year Ended December 31,
	2016			2015			2014
Net (loss) income attributable to Matador Resources Company shareholders — numerator	$	(97,421	)	$	(679,785	)	$	110,771
Weighted average common shares outstanding — denominator
Basic	91,273			81,537			70,229
Dilutive effect of options, restricted stock units and preferred shares	—			—			677
Diluted weighted average common shares outstanding	91,273			81,537			70,906
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	(1.07	)	$	(8.34	)	$	1.58
Diluted	$	(1.07	)	$	(8.34	)	$	1.56

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company.

Credit Risk

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2016 were with Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s Credit Agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

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

Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

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

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

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

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Change in Accounting Principles

During the second quarter of 2016, the Company adopted Accounting Standards Update (“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, requiring either retrospective, modified retrospective or prospective transition. The amended guidance also requires an entity to record excess tax benefits and deficiencies in the income statement. The adoption of this ASU had no impact on any period presented for (i) the Company’s financial position or statements of operations, as the Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of cash flows, as the Company has historically accounted for taxes paid for net share settlement as a financing activity as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of this ASU.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

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

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share data).

	Year Ended December 31,
	2016			2015			2014
Net (loss) income attributable to Matador Resources Company shareholders — numerator	$	(97,421	)	$	(679,785	)	$	110,771
Weighted average common shares outstanding — denominator
Basic	91,273			81,537			70,229
Dilutive effect of options, restricted stock units and preferred shares	—			—			677
Diluted weighted average common shares outstanding	91,273			81,537			70,906
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	(1.07	)	$	(8.34	)	$	1.58
Diluted	$	(1.07	)	$	(8.34	)	$	1.56

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Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Summary of the Company's property and equipment

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2016 and 2015 (in thousands).

	December 31,
	2016			2015
Oil and natural gas properties
Evaluated (subject to amortization)	$	2,408,305		$	2,122,174
Unproved and unevaluated (not subject to amortization)	479,736			387,504
Total oil and natural gas properties	2,888,041			2,509,678
Accumulated depletion	(1,850,882		)	(1,574,040		)
Net oil and natural gas properties	1,037,159			935,638
Other property and equipment
Midstream equipment and facilities	145,662			78,564
Furniture, fixtures and other equipment	5,487			2,918
Software	3,206			2,193
Land	1,437			1,539
Leasehold improvements	5,003			1,173
Total other property and equipment	160,795			86,387
Accumulated depreciation	(13,429		)	(9,619		)
Net other property and equipment	147,366			76,768
Net property and equipment	$	1,184,525		$	1,012,406

Breakdown of the Company's unproved and unevaluated property costs not subject to amortization

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2016 and the year in which these costs were incurred (in thousands).

Description	2016		2015		2014		2013 and prior		Total
Costs incurred for
Property acquisition	$	126,857	$	236,507	$	55,258	$	23,654	$	442,276
Exploration wells	19,017		3,375		34		—		22,426
Development wells	13,086		1,218		730		—		15,034
Total	$	158,960	$	241,100	$	56,022	$	23,654	$	479,736

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of changes in Company's asset retirement obligations

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2016 and 2015 (in thousands).

	Year Ended December 31,
	2016			2015
Beginning asset retirement obligations	$	15,420		$	11,951
Liabilities incurred during period	1,791			4,508
Liabilities settled during period	(375		)	(588		)
Revisions in estimated cash flows	2,622			(1,185		)
Accretion expense	1,182			734
Ending asset retirement obligations	20,640			15,420
Less: current asset retirement obligations (1)	(915		)	(254		)
Long-term asset retirement obligations	$	19,725		$	15,166

__________________

(1) Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2016 and 2015.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Summary of net deferred tax position

The Company’s net deferred tax position as of December 31, 2016 and 2015, respectively, is as follows (in thousands).

	December 31,
	2016			2015
Deferred tax assets
Unrealized loss on derivatives	$	8,734		$	—
Net operating loss carryforwards	137,757			79,208
Alternative minimum tax carryforward	8,633			9,785
Percentage depletion carryover	2,595			2,442
Property and equipment	44,391			42,757
Deferred gain on sale leaseback transaction	—			32,831
Other	—			7,396
Total deferred tax assets	202,110			174,419
Valuation allowance on deferred tax assets	(190,255		)	(154,320		)
Total deferred tax assets, net of valuation allowance	11,855			20,099
Deferred tax liabilities
Unrealized gain on derivatives	(3,800		)	(5,699		)
Other	(8,055		)	(14,400		)
Total deferred tax liabilities	(11,855		)	(20,099		)
Net deferred tax liabilities	$	—		$	—

Income tax expense reconciled to the tax computed at the statutory federal rate

The current income tax provision for the years ended December 31, 2016, 2015 and 2014, respectively, was comprised of the following (in thousands).

	Year Ended December 31,
	2016			2015		2014
Current income tax provision
State income tax	$	108		$	371	$	—
Federal alternative minimum tax	(1,144		)	2,588		133
Net current income tax (benefit) provision	$	(1,036	)	$	2,959	$	133

Reconciliations of the tax (benefit) expense computed at the statutory federal rate to the Company’s total income tax (benefit) provision for the years ended December 31, 2016, 2015 and 2014, respectively, is as follows (in thousands).

	Year Ended December 31,
	2016			2015			2014
Federal tax (benefit) expense at statutory rate (1)	$	(34,333	)	$	(289,412	)	$	61,301
State income tax	539			(13,215		)	2,707
Permanent differences (2)	(499		)	698			397
Federal alternative minimum tax	1,144			(2,588		)	(133		)
Change in federal valuation allowance	33,688			145,777			—
Change in state valuation allowance	(539		)	8,413			(30		)
Net deferred income tax (benefit) provision	—			(150,327		)	64,242
Net current income tax (benefit) provision	(1,036		)	2,959			133
Total income tax (benefit) provision	$	(1,036	)	$	(147,368	)	$	64,375

__________________    

(1) The statutory federal tax rate was 35% for the years ended December 31, 2016, 2015 and 2014.

(2) Amount is primarily attributable to stock-based compensation.

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summarized information about stock options outstanding

Summarized information about stock options outstanding at December 31, 2016 under the 2003 Plan and the 2012 Incentive Plan is as follows.

	Number of options (in thousands)		Weighted average exercise price
Options outstanding at December 31, 2015	2,363		$	15.40
Options granted	668		$	15.51
Options exercised	(114	)	$	10.12
Options forfeited	(28	)	$	19.73
Options expired	(2	)	$	22.66
Options outstanding at December 31, 2016	2,887		$	15.59

Summarized information about outstanding and exercisable stock option

	Options outstanding at December 31, 2016				Options exercisable at December 31, 2016
Range of exercise prices	Shares outstanding (in thousands)	Weighted average remaining contractual life	Weighted average exercise price		Shares exercisable (in thousands)	Weighted average exercise price
$8.18 - $9.55	816	1.30	$	8.30	484	$	8.35
$10.49 - $17.80	925	2.87	$	13.55	302	$	10.58
$18.77 - $22.70	862	3.05	$	21.84	65	$	21.21
$23.40 - $27.33	284	2.26	$	24.22	112	$	23.49

Summary of the non-vested restricted stock and restricted stock units

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2016 is presented below (in thousands, except fair value).

	Restricted Stock				Restricted Stock Units
Non-vested restricted stock and restricted stock units	Shares		Weighted average fair value		Shares		Weighted average fair value
Non-vested at December 31, 2015	854		$	17.64	68		$	21.89
Granted	472		$	18.55	66		$	19.44
Vested	(225	)	$	16.05	(52	)	$	19.67
Forfeited	(62	)	$	20.49	—		—
Non-vested at December 31, 2016	1,039		$	18.23	82		$	21.32

2003 Stock and Incentive Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan

The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.14 years	0.39 years	1.51 years
Risk-free interest rate	1.70%	0.64%	0.74%
Volatility	47.07%	91.98%	55.14%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	—%	—%	—%

2012 Incentive Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan

The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2016, 2015 and 2014.

	2016	2015	2014
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3.96 years	4.00 years	3.99 years
Risk-free interest rate	1.08%	1.15%	1.21%
Volatility	45.68%	56.89%	51.47%
Dividend yield	—%	—%	—%
Estimated forfeiture rate	1.16%	3.21%	4.28%
Weighted average fair value of stock option awards granted during the year	$5.65	$9.90	$9.45

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of contracts for oil and natural gas

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

		Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Liabilities (thousands)
Commodity	Calculation Period
Oil	01/01/2017 - 12/31/2017	2,760,000	$	41.39	$	51.88	$	(18,316	)
Oil	01/01/2018 - 12/31/2018	720,000	$	43.75	$	63.90	(751		)
Natural Gas	01/01/2017 - 12/31/2017	16,860,000	$	2.40	$	3.59	(5,887		)
Total open derivative financial instruments							$	(24,954	)

Summary of offsetting assets

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 consolidated balance sheets as of December 31, 2016 and December 31, 2015 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)
December 31, 2015
Current assets	$	16,767		$	(483	)	$	16,284
Current liabilities	(483		)	483			—
Total	$	16,284		$	—		$	16,284

Summary of offsetting liabilities

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 consolidated balance sheets as of December 31, 2016 and December 31, 2015 (in thousands).

Derivative Instruments	Gross amounts recognized			Gross amounts netted in the consolidated balance sheets			Net amounts presented in the consolidated balance sheets
December 31, 2016
Current liabilities	$	(24,203	)	$	—		$	(24,203	)
Other liabilities	(751		)	—			(751		)
Total	$	(24,954	)	$	—		$	(24,954	)
December 31, 2015
Current assets	$	16,767		$	(483	)	$	16,284
Current liabilities	(483		)	483			—
Total	$	16,284		$	—		$	16,284

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

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

		Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2016			2015			2014
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	5,851		$	62,259		$	5,221
Natural Gas	Revenues: Realized gain (loss) on derivatives	3,435			12,653			(718		)
Natural Gas Liquids (NGL)	Revenues: Realized gain on derivatives	—			2,182			519
Realized gain on derivatives		9,286			77,094			5,022
Oil	Revenues: Unrealized (loss) gain on derivatives	(18,969		)	(31,897		)	47,178
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(22,269		)	(5,440		)	9,087
Natural Gas Liquids (NGL)	Revenues: Unrealized (loss) gain on derivatives	—			(1,928		)	2,037
Unrealized (loss) gain on derivatives		(41,238		)	(39,265		)	58,302
Total		$	(31,952	)	$	37,829		$	63,324

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

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

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

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

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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum lease payments required under the office lease agreement

The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2016 (in thousands).

Year Ending December 31,	Amount
2017	$	2,443
2018	2,495
2019	2,528
2020	2,602
2021	2,660
Thereafter	12,335
Total	$	25,063

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Supplemental Disclosures (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Disclosures [Abstract]

Summary of current accrued liabilities

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

	December 31,
	2016		2015
Accrued evaluated and unproved and unevaluated property costs	$	54,273	$	54,586
Accrued support equipment and facilities costs	15,139		17,393
Accrued lease operating expenses	16,009		7,743
Accrued interest on debt	6,541		5,806
Accrued asset retirement obligations	915		254
Accrued partners’ share of joint interest charges	5,572		4,565
Other	3,011		2,022
Total accrued liabilities	$	101,460	$	92,369

Supplemental disclosures of cash flow information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Cash paid for income taxes	$	2,895		$	506		$	94
Cash paid for interest expense, net of amounts capitalized	27,464			16,154			5,269
Increase in asset retirement obligations related to mineral properties	3,817			2,510			3,843
Increase in asset retirement obligations related to support equipment and facilities	222			383			120
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	1,775			(30,683		)	32,972
(Decrease) increase in liabilities for support equipment and facilities	(588		)	12,076			4,290
Issuance of restricted stock units for Board and advisor services	992			584			444
Stock-based compensation expense recognized as liability	569			79			223
Increase in liabilities for accrued cost to issue equity	343			—			—
Transfer of inventory to oil and natural gas properties	395			615			216

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Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2016
Oil and natural gas revenues	$	289,512		$	1,644	$	—		$	—		$	291,156
Midstream services revenues	—			18,982		—			(13,764		)	5,218
Realized gain on derivatives	9,286			—		—			—			9,286
Unrealized gain on derivatives	(41,238		)	—		—			—			(41,238		)
Expenses (1)	391,098			8,254		56,001			(13,764		)	441,589
Operating (loss) income (2)	$	(133,538	)	$	12,372	$	(56,001	)	$	—		$	(177,167	)
Total Assets	$	1,098,525		$	140,459	$	225,681		$	—		$	1,464,665
Capital Expenditures	$	379,881		$	67,566	$	6,913		$	—		$	454,360

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $118.4 million, $2.7 million and $0.9 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.

(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

	Exploration and Production											Consolidated Company
				Midstream		Corporate			Eliminations
Year Ended December 31, 2015
Oil and natural gas revenues	$	277,844		$	496	$	—		$	—		$	278,340
Midstream services revenues	—			11,485		—			(9,621		)	1,864
Realized gain on derivatives	77,094			—		—			—			77,094
Unrealized loss on derivatives	(39,265		)	—		—			—			(39,265		)
Expenses (1)	1,078,534			5,178		50,604			(9,621		)	1,124,695
Operating (loss) income (2)	$	(762,861	)	$	6,803	$	(50,604	)	$	—		$	(806,662	)
Total Assets	$	1,000,075		$	75,980	$	64,806		$	—		$	1,140,861
Capital Expenditures (3)	$	622,642		$	75,009	$	786		$	—		$	698,437

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $176.7 million, $1.6 million and $0.5 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment.

(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) In October 2015, the Company sold the Wolf Processing Plant to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets.

	Exploration and Production										Consolidated Company
			Midstream		Corporate			Eliminations
Year Ended December 31, 2014
Oil and natural gas revenues	$	366,191	$	1,521	$	—		$	—		$	367,712
Midstream services revenues	—		4,929		—			(3,716		)	1,213
Realized gain on derivatives	5,022		—		—			—			5,022
Unrealized loss on derivatives	58,302		—		—			—			58,302
Expenses (1)	220,374		2,703		32,557			(3,716		)	251,918
Operating (loss) income (2)	$	209,141	$	3,747	$	(32,557	)	$	—		$	180,331
Total Assets	$	1,388,261	$	35,100	$	11,129		$	—		$	1,434,490
Capital Expenditures	$	597,351	$	12,504	$	517		$	—		$	610,372

_____________________

(1) Expenses include depreciation, depletion and amortization expenses of $133.1 million, $1.2 million and $0.4 million for the exploration and production, midstream and corporate segments, respectively.

(2) Includes $17,000 in net loss attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2016

Subsequent Events [Abstract]

Pro Forma Information

CONSOLIDATED BALANCE SHEET

	December 31, 2016
	As Reported			Adjustment			Pro Forma
ASSETS
Current assets
Cash	$	212,884		$	164,340	(1)	$	377,224
Restricted cash	1,258			9,407		(2)	10,665
Accounts receivable							—
Oil and natural gas revenues	34,154			—			34,154
Joint interest billings	19,347			—			19,347
Other	5,167			—			5,167
Lease and well equipment inventory	3,045			—			3,045
Prepaid expenses and other assets	3,327			—			3,327
Total current assets	279,182			173,747			452,929
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated	2,408,305			—			2,408,305
Unproved and unevaluated	479,736			—			479,736
Other property and equipment	160,795			—			160,795
Less accumulated depletion, depreciation and amortization	(1,864,311		)	—			(1,864,311		)
Net property and equipment	1,184,525			—			1,184,525
Other assets	958						958
Total assets	$	1,464,665		$	173,747		$	1,638,412
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	4,674		$	—		$	4,674
Accrued liabilities	101,460			—			101,460
Royalties payable	23,988			—			23,988
Amounts due to affiliates	8,651			—			8,651
Derivative instruments	24,203			—			24,203
Advances from joint interest owners	1,700			—			1,700
Amounts due to joint ventures	4,251			—			4,251
Other current liabilities	578			—			578
Total current liabilities	169,505			—			169,505
Long-term liabilities
Senior unsecured notes payable	573,924			—			573,924
Asset retirement obligations	19,725			—			19,725
Derivative instruments	751			—			751
Amounts due to joint ventures	1,771			—			1,771
Other long-term liabilities	7,544			—			7,544
Total long-term liabilities	603,715			—			603,715
Commitments and contingencies (Note 13)
Shareholders’ equity
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995			—			995
Additional paid-in capital	1,325,481			124,871		(3)	1,450,352
Accumulated deficit	(636,351		)	—			(636,351		)
Total Matador Resources Company shareholders’ equity	690,125			124,871			814,996
Non-controlling interest in subsidiaries	1,320			48,876		(4)	50,196
Total shareholders’ equity	691,445			173,747			865,192
Total liabilities and shareholders’ equity	$	1,464,665		$	173,747		$	1,638,412

______________________

(1) Represents $176.4 million of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately $2.6 million paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and (ii) $10.0 million of cash restricted to operations of San Mateo. Also reflects $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources not previously owned by the Company.

(2) Represents $10.0 million in cash contributed to San Mateo less $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own.

(3) Reflects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the amount received in connection with the formation of San Mateo.

(4) Represents the adjustment required to reflect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and Five Point’s 49% non-controlling interest in San Mateo.

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Condensed Consolidated Statements (Tables)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidated Balance Sheets

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

Condensed Consolidating Balance Sheet December 31, 2015
	Matador		Non-Guarantor Subsidiaries		Existing Guarantor Subsidiaries		Eliminating Entries			Consolidated
ASSETS
Intercompany receivable	$	304,573	$	1,463	$	11,928	$	(317,964	)	$	—
Other current assets	289		1,141		125,577		—			127,007
Net property and equipment	—		47,535		964,871		—			1,012,406
Investment in subsidiaries	584,461		—		20,355		(604,816		)	—
Other long-term assets	—		—		1,448		—			1,448
Total assets	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	$	1,140,861
LIABILITIES AND EQUITY
Intercompany payable	$	—	$	11,928	$	306,036	$	(317,964	)	$	—
Other current liabilities	10,066		16,557		110,207		—			136,830
Senior unsecured notes payable	391,254		—		—		—			391,254
Other long-term liabilities	—		343		123,475		—			123,818
Total equity attributable to Matador Resources Company	488,003		20,355		584,461		(604,816		)	488,003
Non-controlling interest in subsidiaries	—		956		—		—			956
Total liabilities and equity	$	889,323	$	50,139	$	1,124,179	$	(922,780	)	1,140,861

Condensed Consolidated Statements of Operations

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	17,302		$	257,828		$	(10,708	)	$	264,422
Total expenses	5,319			7,031			439,947			(10,708		)	441,589
Operating (loss) income	(5,319		)	10,271			(182,119		)	—			(177,167		)
Net gain on asset sales and inventory impairment	—			—			107,277			—			107,277
Interest expense	(28,199		)	—			—			—			(28,199		)
Other expense	—			—			(4		)	—			(4		)
(Loss) earnings in subsidiaries	(64,349		)	—			9,810			54,539			—
(Loss) income before income taxes	(97,867		)	10,271			(65,036		)	54,539			(98,093		)
Total income tax (benefit) provision	(446		)	97			(687		)	—			(1,036		)
Net income attributable to non-controlling interest in subsidiaries	—			(364		)	—			—			(364		)
Net (loss) income attributable to Matador Resources Company	$	(97,421	)	$	9,810		$	(64,349	)	$	54,539		$	(97,421	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	6,310		$	316,067		$	(4,344	)	$	318,033
Total expenses	5,739			2,944			1,120,356			(4,344		)	1,124,695
Operating (loss) income	(5,739		)	3,366			(804,289		)	—			(806,662		)
Net gain on asset sales and inventory impairment	—			—			908			—			908
Interest expense	(20,511		)	—			(1,243		)	—			(21,754		)
Other income	—			—			616			—			616
(Loss) earnings in subsidiaries	(658,698		)	—			2,458			656,240			—
(Loss) income before income taxes	(684,948		)	3,366			(801,550		)	656,240			(826,892		)
Total income tax (benefit) provision	(5,163		)	647			(142,852		)	—			(147,368		)
Net income attributable to non-controlling interest in subsidiaries	—			(261		)	—			—			(261		)
Net (loss) income attributable to Matador Resources Company	$	(679,785	)	$	2,458		$	(658,698	)	$	656,240		$	(679,785	)

Condensed Consolidating Statement of Operations For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Total revenues	$	—		$	—		$	432,249		$	—		$	432,249
Total expenses	3,389			111			248,418			—			251,918
Operating (loss) income	(3,389		)	(111		)	183,831			—			180,331
Net gain on asset sales and inventory impairment	—			—			—			—			—
Interest expense	—			—			(5,334		)	—			(5,334		)
Other income	—			—			132			—			132
Earnings (loss) in subsidiaries	112,908			—			(94		)	(112,814		)	—
Income (loss) before income taxes	109,519			(111		)	178,535			(112,814		)	175,129
Total income tax (benefit) provision	(1,252		)	—			65,627			—			64,375
Net loss attributable to non-controlling interest in subsidiaries	—			17			—			—			17
Net income (loss) attributable to Matador Resources Company	$	110,771		$	(94	)	$	112,908		$	(112,814	)	$	110,771

Condensed Consolidated Statements of Cash Flows

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(45,215	)	$	6,694		$	172,607		$	—		$	134,086
Net cash used in investing activities	(324,724		)	(64,683		)	(401,034		)	384,801			(405,640		)
Net cash provided by financing activities	469,654			60,110			322,743			(384,801		)	467,706
Increase in cash	99,715			2,121			94,316			—			196,152
Cash at beginning of year	80			186			16,466			—			16,732
Cash at end of year	$	99,795		$	2,307		$	110,782		$	—		$	212,884

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(31,271	)	$	13,916		$	225,890		$	—		$	208,535
Net cash used in investing activities	(546,715		)	(31,101		)	(410,843		)	563,505			(425,154		)
Net cash provided by financing activities	577,973			17,353			193,123			(563,505		)	224,944
Increase in cash	(13		)	168			8,170			—			8,325
Cash at beginning of year	93			18			8,296			—			8,407
Cash at end of year	$	80		$	186		$	16,466		$	—		$	16,732

Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2014
	Matador			Non-Guarantor Subsidiaries			Existing Guarantor Subsidiaries			Eliminating Entries			Consolidated
Net cash (used in) provided by operating activities	$	(8,607	)	$	431		$	259,657		$	—		$	251,481
Net cash used in investing activities	(172,749		)	(1,763		)	(569,968		)	173,949			(570,531		)
Net cash provided by financing activities	181,328			1,350			312,441			(173,949		)	321,170
Increase in cash	(28		)	18			2,130			—			2,120
Cash at beginning of year	121			—			6,166			—			6,287
Cash at end of year	$	93		$	18		$	8,296		$	—		$	8,407

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Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) shares	Dec. 31, 2016 USD ($) $ / MMBTU	Dec. 31, 2016 USD ($) $ / bbl	Dec. 31, 2016 USD ($) Purchasers	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) shares	Dec. 31, 2015 USD ($) $ / MMBTU	Dec. 31, 2015 USD ($) $ / bbl	Dec. 31, 2015 USD ($) Purchasers	Dec. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 $ / MMBTU	Dec. 31, 2014 $ / bbl	Dec. 31, 2014 Purchasers	Dec. 31, 2014	Dec. 31, 2014 USD ($)	Feb. 22, 2017 USD ($)	Dec. 09, 2016 USD ($)	Jan. 31, 2016 USD ($)	Apr. 14, 2015 USD ($)
Summary of Significant Accounting Policies [Line Items]
Midstream services revenues							$ 5,218,000						$ 1,864,000					$ 1,213,000
Midstream operating costs							5,389,000						3,489,000					1,408,000
Borrowings under Credit Agreement	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	0
Senior unsecured notes payable	573,924,000	573,924,000	573,924,000	573,924,000	573,924,000	573,924,000	573,924,000	$ 391,254,000	$ 391,254,000	$ 391,254,000	$ 391,254,000	$ 391,254,000	391,254,000
Restricted cash	$ 1,258,000	1,258,000	1,258,000	1,258,000	1,258,000	1,258,000	1,258,000	$ 44,357,000	$ 44,357,000	$ 44,357,000	$ 44,357,000	$ 44,357,000	44,357,000								$ 42,100,000
Billing date	30 days
Outstanding days of account receivable	60 days
Allowance for doubtful accounts	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	0
Capitalized general and administrative costs							15,700,000						6,900,000					6,400,000
Capitalized interest expense							3,700,000						3,900,000					2,800,000
Present value discounted percent of future net revenues of proved oil and natural gas reserves						10.00%
Average oil and natural gas prices			2.48	39.25					2.59	46.79				4.35	91.48
Net capitalized costs less related deferred income taxes exceeded the full-cost ceiling																		0
Impairment charge of net capitalized costs							158,633,000						801,166,000					0
Number of purchasers | Purchasers					3						3					3
Stock-based compensation (non-cash) expense							12,362,000						9,450,000					5,524,000
Common stock and restricted stock unit expense							1,000,000						900,000					300,000
Percentage being realized up on ultimate settlement						50.00%
Machinery and Equipment [Member]
Summary of Significant Accounting Policies [Line Items]
Useful life using the straight-line	30 years
Maximum [Member]
Summary of Significant Accounting Policies [Line Items]
Accounts receivable due period	60 days
Useful life	30 years
Minimum [Member]
Summary of Significant Accounting Policies [Line Items]
Accounts receivable due period	30 days
Useful life	5 years
Accounts Receivable [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						38.00%						39.00%					44.00%
Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						48.00%						59.00%					68.00%
Stock options [Member]
Summary of Significant Accounting Policies [Line Items]
Stock-based compensation (non-cash) expense							$ 5,900,000						4,700,000					2,500,000
Restricted Stock Units (RSUs) [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares		90,552						73,923
Restricted stock [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares		1,039,292						854,238
Stock options [Member]
Summary of Significant Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares		2,886,821						2,362,861
Senior Notes Due 2023 [Member] | Unsecured Debt [Member]
Summary of Significant Accounting Policies [Line Items]
Senior unsecured notes payable																				$ 175,000,000		$ 400,000,000
Subsequent Event [Member]
Summary of Significant Accounting Policies [Line Items]
Borrowings under Credit Agreement																			$ 0
Reclassification from Other Income to Third-Party Midstream Services Revenue [Member] | Restatement Adjustment [Member]
Summary of Significant Accounting Policies [Line Items]
Midstream services revenues													1,800,000					1,200,000
Reclassification from Lease Operating Expenses to Plant and Other Midstream Services Operating Expenses [Member] | Restatement Adjustment [Member]
Summary of Significant Accounting Policies [Line Items]
Midstream operating costs													$ 3,500,000					$ 1,400,000
Plains Marketing [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						18.00%
Shell Trading (US) Company [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						17.00%						33.00%					45.00%
Occidental Energy Marketing [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage						13.00%
Enterprise Crude Oil LLC [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage												14.00%					12.00%
Sequent Energy Management [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage												12.00%
Enterprise Products Operating [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Summary of Significant Accounting Policies [Line Items]
Concentration risk, percentage																	11.00%

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Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to Matador Resources Company shareholders — numerator	$ (97,421)	$ (679,785)	$ 110,771
Weighted average common shares outstanding — denominator
Weighted average common shares outstanding for basic earnings (loss) per share	91,273,000	81,537,000	70,229,000
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	0	677,000
Diluted weighted average common shares outstanding	91,273,000	81,537,000	70,906,000
Earnings (loss) per common share
Basic (usd per share)	$ (1.07)	$ (8.34)	$ 1.58
Diluted (usd per share)	$ (1.07)	$ (8.34)	$ 1.56
Stock options [Member]
Earnings (loss) per common share
Total (usd per share)	2,886,821	2,362,861
Restricted Stock Units (RSUs) [Member]
Earnings (loss) per common share
Total (usd per share)	90,552	73,923
Restricted stock [Member]
Earnings (loss) per common share
Total (usd per share)	1,039,292	854,238

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Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and natural gas properties
Evaluated (subject to amortization)	$ 2,408,305	$ 2,122,174
Total unproved and unevaluated	479,736	387,504
Total oil and natural gas properties	2,888,041	2,509,678
Accumulated depletion	(1,850,882)	(1,574,040)
Net oil and natural gas properties	1,037,159	935,638
Other property and equipment
Other property and equipment	160,795	86,387
Accumulated depreciation	(13,429)	(9,619)
Net other property and equipment	147,366	76,768
Net property and equipment	1,184,525	1,012,406
Midstream equipment and facilities
Other property and equipment
Other property and equipment	145,662	78,564
Furniture, fixtures and other equipment
Other property and equipment
Other property and equipment	5,487	2,918
Software
Other property and equipment
Other property and equipment	3,206	2,193
Land
Other property and equipment
Other property and equipment	1,437	1,539
Leasehold improvements
Other property and equipment
Other property and equipment	$ 5,003	$ 1,173

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Property and Equipment (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2011
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Total unproved and unevaluated	$ 479,736	$ 387,504
2016
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	126,857
Exploration wells	19,017
Amount for development wells	13,086
Total unproved and unevaluated	158,960
2015
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition		236,507
Exploration wells		3,375
Amount for development wells		1,218
Total unproved and unevaluated		$ 241,100
2014
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition			$ 55,258
Exploration wells			34
Amount for development wells			730
Total unproved and unevaluated			$ 56,022
2013 and prior
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition				$ 23,654
Exploration wells				0
Amount for development wells				0
Total unproved and unevaluated				$ 23,654
Total
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	442,276
Exploration wells	22,426
Amount for development wells	15,034
Total unproved and unevaluated	$ 479,736

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Property and Equipment (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Property, Plant and Equipment [Abstract]
Amortization costs	$ 37.5
Anticipated amount for wells	$ 37.5

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations	$ 15,420	$ 11,951
Liabilities incurred during period	1,791	4,508
Liabilities settled during period	(375)	(588)
Revisions in estimated cash flows	2,622	(1,185)
Accretion expense	1,182	734
Ending asset retirement obligations	$ 15,420	$ 11,951	$ 20,640	$ 15,420
Less: current asset retirement obligations			(915)	(254)
Long-term asset retirement obligations			$ 19,725	$ 15,166

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Business Combinations and Divestitures (Details) $ in Millions			12 Months Ended
	Oct. 01, 2015 USD ($)	Feb. 27, 2015 USD ($) a shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Carrying value of net assets sold			$ 31.0
Sale leaseback transaction, transaction costs			0.4
Sale leaseback transaction, current period gain recognized			107.3
Harvey E Yates Company [Member]
Business Acquisition [Line Items]
Number of gross acres in acreage acquired | a		58,600
Number of net acres in acreage acquired | a		18,200
Business combination, consideration transferred, liabilities incurred		$ 33.6
Shares issued upon conversion | shares		10
Purchase price adjustments for production, revenues and operating and capital expenditures		$ 4.5
Liabilities assumed		4.5
Transaction costs				$ 2.5
Total consideration given		223.5
Deferred tax liabilities incurred		$ (76.8)
Harvey E Yates Company [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Shares issued for acquisition | shares		3,300,000
Harvey E Yates Company [Member] | Convertible Preferred Stock [Member]
Business Acquisition [Line Items]
Shares issued for acquisition | shares		150,000
EnLink [Member]
Business Acquisition [Line Items]
Purchase price adjustments for production, revenues and operating and capital expenditures	$ 3.6
Proceeds from sale of oil and gas property and equipment	143.4
Proceeds from sale of oil and gas property and equipment net of purchase price adjustments	$ 139.8
Gas gathering and processing agreement, term	15 years
Sale leaseback transaction, deferred gain			$ 108.4

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Revolving Credit Agreement (Details Textual) - USD ($)				1 Months Ended	12 Months Ended
	Dec. 09, 2016	Mar. 11, 2016	Apr. 14, 2015	Sep. 30, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 22, 2017	Oct. 31, 2016	Oct. 30, 2016	Oct. 21, 2015	Sep. 28, 2012
Revolving Credit Agreement (Textual) [Abstract]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 400,000	$ 800,000			$ 1,190,000	$ 1,151,000	$ 590,000
Senior unsecured notes payable					573,924,000	$ 391,254,000
Repayments of borrowings under Credit Agreement					$ 120,000,000
Repay deficit in agreement Period					6 months
Borrowings under Credit Agreement					$ 0
Borrowings interest rate			50.00%
Outstanding letters of credit					800,000
Deferred loan costs					1,300,000
Proceeds from Issuance or Sale of Equity	181,500,000
Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Company amended and restated its senior secured revolving credit agreement				September 28, 2012
Senior secured revolving credit maximum facility									$ 400,000,000	$ 300,000,000		$ 400,000,000
Maximum borrowing capacity, amended					$ 500,000,000
Debt to EBITDA ratio covenant					4.25
Percentage of reserves required to maintain					100.00%
Subsequent Event [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under Credit Agreement								$ 0
Outstanding letters of credit								$ 800,000
LIBOR rate [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate					1.00%
Maximum [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Commitment fee percentage					0.50%
Minimum [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Commitment fee percentage					0.375%
Minimum [Member] | Base rate loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate					0.50%
Eurodollar [Member] | Maximum [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate					2.50%
Eurodollar [Member] | Minimum [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate					1.50%
Unsecured Debt [Member] | Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Senior unsecured notes payable	$ 175,000,000		$ 400,000,000
Stated interest rate			6.875%								6.875%
Maturity date			Apr. 15, 2023
Percentage of principal amount redeemed			35.00%
Effective interest rate					5.50%
Percentage of aggregate principal amount of notes outstanding after redemption			65.00%
Percentage of principal amount outstanding			25.00%
Period of default when due of interest			30 days
Period after notice to comply with reporting obligations			180 days
Period after notice to comply with agreements in indenture			60 days
Aggregate principal amount related to payment defaults or accelerations			$ 25,000,000.0
Amount of failure to pay final judgments			$ 25,000,000.0
Period for failure to pay final judgments			60 days
Federal Funds Effective Rate [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate					0.50%
Base rate loan [Member] | Maximum [Member] | Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate					1.50%
Debt Redemption, 2018 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price			105.156%
Percentage of principal amount redeemed	105.50%		106.875%
Debt Redemption, 2019 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price			103.438%
Debt Redemption, 2020 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price			101.719%
Debt Redemption, 2021 and thereafter [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member]
Revolving Credit Agreement (Textual) [Abstract]
Redemption Price			100.00%

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Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current State and Local Tax Expense (Benefit)	$ 108	$ 371	$ 0
Deferred tax assets
Unrealized loss on derivatives	8,734	0
Net operating loss carryforwards	137,757	79,208
Alternative minimum tax carryforward	8,633	9,785
Percentage depletion carryover	2,595	2,442
Property and equipment	44,391	42,757
Deferred gain on sale leaseback transaction	0	32,831
Other	0	7,396
Total deferred tax assets	202,110	174,419
Valuation allowance on deferred tax assets	(190,255)	(154,320)
Total deferred tax assets, net of valuation allowance	11,855	20,099
Deferred tax liabilities
Unrealized gain on derivatives	3,800	5,699
Other	(8,055)	(14,400)
Total deferred tax liabilities	(11,855)	(20,099)
Net deferred tax liabilities	0	0
Current Federal Tax Expense (Benefit)	(1,144)	2,588	133
Net current income tax (benefit) provision	$ (1,036)	$ 2,959	$ 133

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Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Full-cost ceiling impairment	$ 158,633	$ 801,166	$ 0
Increase in valuation allowance	(33,688)	$ (145,777)	$ 0
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	375,900
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 6,200

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Income Taxes (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income tax provision
State income tax	$ 108	$ 371	$ 0
Federal alternative minimum tax	(1,144)	2,588	133
Net current income tax (benefit) provision	(1,036)	2,959	133
Deferred income tax provision (benefit)
Federal tax (benefit) expense at statutory rate	(34,333)	(289,412)	61,301
State income tax	539	(13,215)	2,707
Permanent differences	(499)	698	397
Federal alternative minimum tax	1,144	(2,588)	(133)
Change in federal valuation allowance	33,688	145,777	0
Change in state valuation allowance	(539)	8,413	(30)
Net deferred income tax (benefit) provision	0	(150,327)	64,242
Total income tax (benefit) provision	$ (1,036)	$ (147,368)	$ 64,375
Federal statutory rate	35.00%	35.00%	35.00%

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Stock-Based Compensation (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	$ 25.76
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Weighted average fair value of stock option awards granted during the year	$ 5.65	$ 9.90	$ 9.45
Stock Based Compensation Two Thousand Twelve Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model	Black Scholes Merton		Black Scholes Merton
Expected option life	3 years 11 months 16 days	4 years	3 years 11 months 27 days
Risk-free interest rate	1.08%	1.15%	1.21%
Volatility	45.68%	56.89%	51.47%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	1.16%	3.21%	4.28%
2003 Stock and Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model	Black Scholes Merton	Black Scholes Merton	Black Scholes Merton
Expected option life	3 years 1 month 21 days	4 months 21 days	1 year 6 months 4 days
Risk-free interest rate	1.70%	0.64%	0.74%
Volatility	47.07%	91.98%	55.14%
Dividend yield	0.00%	0.00%	0.00%
Estimated forfeiture rate	0.00%	0.00%	0.00%

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Stock-Based Compensation (Details 1) shares in Thousands	12 Months Ended
	Dec. 31, 2016 $ / shares shares
Number of options (in thousands)
Options outstanding at December 31, 2015 | shares	2,363
Options granted | shares	668
Options exercised | shares	(114)
Options forfeited | shares	(28)
Options expired | shares	(2)
Options outstanding at December 31, 2016 | shares	2,887
Weighted average exercise price
Weighted average exercise price, Options outstanding Beginning Balance | $ / shares	$ 15.40
Weighted average exercise price, Options granted | $ / shares	15.51
Weighted average exercise price, Options exercised | $ / shares	10.12
Weighted average exercise price, Options forfeited | $ / shares	19.73
Weighted average exercise price, Options expired | $ / shares	22.66
Weighted average exercise price, Options outstanding Ending Balance | $ / shares	$ 15.59

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Stock-Based Compensation (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Deferred Compensation Liability, Current	$ 0.0	$ 1.0	$ 0.0
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options	$ 0.5	$ 0.3	$ 0.1
$8.18 - $9.55 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	$ 8.18
Range of exercise prices, Upper limit	$ 9.55
Shares outstanding	816
Weighted average remaining contractual price	1 year 3 months 18 days
Weighted average exercise price	$ 8.30
Shares exercisable	484
Weighted average exercise price	$ 8.35
$10.49 - $17.80 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	10.49
Range of exercise prices, Upper limit	$ 17.80
Shares outstanding	925
Weighted average remaining contractual price	2 years 10 months 13 days
Weighted average exercise price	$ 13.55
Shares exercisable	302
Weighted average exercise price	$ 10.58
$18.77 - $22.70 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	18.77
Range of exercise prices, Upper limit	$ 22.70
Shares outstanding	862
Weighted average remaining contractual price	3 years 18 days
Weighted average exercise price	$ 21.84
Shares exercisable	65
Weighted average exercise price	$ 21.21
$23.40-27.33 Range [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	23.40
Range of exercise prices, Upper limit	$ 27.33
Shares outstanding	284
Weighted average remaining contractual price	2 years 3 months 4 days
Weighted average exercise price	$ 24.22
Shares exercisable	112
Weighted average exercise price	$ 23.49

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Stock-Based Compensation (Details 3) shares in Thousands	12 Months Ended
	Dec. 31, 2016 $ / shares shares
Restricted Stock Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance | shares	854
Shares Granted | shares	472
Shares Vested | shares	(225)
Shares Forfeited | shares	(62)
Non-vested Shares, Ending Balance | shares	1,039
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average fair value, Beginning Balance | $ / shares	$ 17.64
Weighted average fair value, Granted | $ / shares	18.55
Weighted average fair value, Vested | $ / shares	16.05
Weighted average fair value, Forfeited | $ / shares	20.49
Weighted average fair value, Ending Balance | $ / shares	$ 18.23
Restricted Stock Units Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance | shares	68
Shares Granted | shares	66
Shares Vested | shares	(52)
Shares Forfeited | shares	0
Non-vested Shares, Ending Balance | shares	82
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average fair value, Beginning Balance | $ / shares	$ 21.89
Weighted average fair value, Granted | $ / shares	19.44
Weighted average fair value, Vested | $ / shares	19.67
Weighted average fair value, Forfeited | $ / shares	0.00
Weighted average fair value, Ending Balance | $ / shares	$ 21.32

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Stock Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Feb. 16, 2017	Feb. 15, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 10, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares of common stock provided						8,700,000
Aggregate intrinsic value			$ 29,400
Aggregate intrinsic value exercisable			$ 13,600
Quoted closing market price			$ 25.76
Weighted average contractual term			1 year 1 month 39 days
Total intrinsic value of options exercised			$ 1,600	$ 1,300	$ 200
Tax related benefits realized from the exercise of stock options			500	300	100
Stock-based compensation expense			12,362	9,450	5,524
Stock based long term liability			1,400	0	1,400
Stock based current liability			0	1,000	0
Unrecognized compensation expense related to unvested stock options			$ 6,900
Weighted average remaining requisite service period of unvested stock awards			1 year 10 months 24 days
Fair value of option shares vested			$ 3,000	1,300	1,500
Options granted			668,000
Restricted stock or unit expenses				0	3,023
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding			$ 28,900
Tax benefits recognized for stock based compensation			$ 4,300	3,400	1,900
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			3 years
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares			4 years
Class A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares that may be issued pursuant to options or restricted stock grants			3,481,569
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining requisite service period of unvested stock awards			1 year 9 months 4 days
Restricted stock or unit expenses			$ 6,600	4,700	3,000
Unrecognized compensation expense related to unvested restricted stock and restricted stock units			12,500
Fair value of restricted stock and restricted stock units vested			$ 4,600	800	900
Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum vesting period			5 years
Maximum vesting period			10 years
Stock-based compensation expense			$ 5,900	$ 4,700	$ 2,500
Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted	444,491	590,128
Share Based Compensation Arrangement By Share Based Payment Award Options and Restricted Stock Grants In Period Fair Value	$ 9,300	$ 12,400
Subsequent Event [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares	3 years	3 years
Restricted stock grants	174,561	228,174
Weighted average fair value, Granted	$ 26.86	$ 27.26
Subsequent Event [Member] | Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares	3 years	3 years
Restricted stock grants	174,561	228,174
Weighted average fair value, Granted	$ 26.86	$ 27.26

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Employee Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Benefit Plan (Textual) [Abstract]
Employees annual compensation	3.00%
Safe Harbor match	$ 0.7	$ 0.6	$ 0.4
Discretionary matching contributions	0.9	0.8	0.5
No additional discretionary contributions	$ 0.0	$ 0.0	$ 0.0

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Equity (Details) - USD ($) $ in Thousands							12 Months Ended
	Dec. 09, 2016	Mar. 11, 2016	Apr. 21, 2015	Apr. 06, 2015	Feb. 27, 2015	May 29, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 02, 2015	Apr. 01, 2015
Subsidiary, Sale of Stock [Line Items]
Sale of Stock, Consideration Received on Transaction	$ 145,800	$ 141,500
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 400	$ 800					$ 1,190	$ 1,151	$ 590
Common stock, shares authorized							120,000,000	120,000,000
Offering costs			$ 1,200			$ 600
Proceeds from issuance of common stock			$ 187,600			$ 181,300	$ 288,510	$ 188,720	181,875
Repayments of long-term debt							$ 120,000	$ 476,982	$ 180,000
Common Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	6,000,000	7,500,000
Common stock, shares authorized										120,000,000	80,000,000
Shares converted				1,500,000
Shares held in escrow				166,667
Issuance of Class A common stock, shares			7,000,000			7,500,000
Harvey E Yates Company [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued upon conversion					10
Harvey E Yates Company [Member] | Convertible Preferred Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued for acquisition					150,000
Shares issued as consideration in business combination					150,000
Harvey E Yates Company [Member] | Common Stock [Member]
Subsidiary, Sale of Stock [Line Items]
Shares issued for acquisition					3,300,000

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Derivative Financial Instruments (Details) $ in Thousands	Feb. 22, 2017 bbl $ / bbl	Dec. 31, 2016 USD ($) bbl MMBTU $ / MMBTU $ / bbl
Open costless collar contracts [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability) | $		$ (24,954)
Open costless collar contracts [Member] | Oil, Calculation Period One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		2,760,000
Summary of contracts for oil and natural gas
Price Floor		41.39
Price Ceiling		51.88
Fair Value of Asset (Liability) | $		$ (18,316)
Open costless collar contracts [Member] | Oil, Calculation Period Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		720,000
Summary of contracts for oil and natural gas
Price Floor		43.75
Price Ceiling		63.90
Fair Value of Asset (Liability) | $		$ (751)
Open costless collar contracts [Member] | Natural Gas, Calculation Period One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		16,860,000
Summary of contracts for oil and natural gas
Price Floor | $ / MMBTU		2.40
Price Ceiling | $ / MMBTU		3.59
Fair Value of Asset (Liability) | $		$ (5,887)
Subsequent Event [Member] | Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,890,000
Summary of contracts for oil and natural gas
Price Floor	50.00
Price Ceiling	60.75

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Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Offsetting Derivative Assets [Abstract]
Derivative Liability	$ 24,954	$ 0
Offsetting Derivative Liabilities [Abstract]
Derivative Asset	0	16,284
Current liabilities [Member]
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(24,203)	(483)
Gross amounts netted in the consolidated balance sheet	0	(483)
Derivative Liability	24,203	0
Other liabilities [Member]
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized liabilities	(751)
Gross amounts netted in the consolidated balance sheet	0
Derivative Liability	$ 751
Other Current Assets [Member]
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets		16,767
Gross amounts netted in the consolidated balance sheets		(483)
Derivative Asset		$ 16,284

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Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Third-party midstream services revenues	$ 9,286	$ 77,094	$ 5,022
Unrealized (loss) gain on derivatives	(41,238)	(39,265)	58,302
Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Third-party midstream services revenues	9,286	77,094	5,022
Unrealized (loss) gain on derivatives	(41,238)	(39,265)	58,302
Total	(31,952)	37,829	63,324
Oil [Member] | Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Third-party midstream services revenues	5,851	62,259	5,221
Unrealized (loss) gain on derivatives	(18,969)	(31,897)	47,178
Natural Gas [Member] | Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Third-party midstream services revenues	3,435	12,653	(718)
Unrealized (loss) gain on derivatives	(22,269)	(5,440)	9,087
NGL's [Member] | Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Third-party midstream services revenues	0	2,182	519
Unrealized (loss) gain on derivatives	$ 0	$ (1,928)	$ 2,037

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets (Liabilities)
Derivative Liability	$ 24,954	$ 0
Fair value on a recurring basis [Member]
Assets (Liabilities)
Derivative Liability	(24,954)	16,284
Derivative, Fair Value, Net	(24,954)
Fair value on a recurring basis [Member] | Oil [Member]
Assets (Liabilities)
Derivative Assets (Liabilities), at Fair Value, Net		16,284
Fair value on a recurring basis [Member] | Level 1 [Member]
Assets (Liabilities)
Derivative Liability	0	0
Fair value on a recurring basis [Member] | Level 2 [Member]
Assets (Liabilities)
Derivative Liability	(24,954)	16,284
Derivative, Fair Value, Net		16,284
Fair value on a recurring basis [Member] | Level 3 [Member]
Assets (Liabilities)
Derivative Liability	$ 0	$ 0

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Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of notes payable	$ 605,200,000	$ 381,000,000
Notes outstanding	573,924,000	391,254,000
Pipe and other equipment [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment charge for equipments held in inventory	$ 0	$ 0

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Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Schedule of future minimum lease payments required under the office lease agreement
2016	$ 2,443
2017	2,495
2018	2,528
2019	2,602
2020	2,660
Thereafter	12,335
Total	$ 25,063

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Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Term of leases	5 years
Rent expense, including fees for operating expenses and consumption of electricity	$ 2.9	$ 1.7	$ 0.9
Minimum outstanding commitments	$ 11.1
Term Of Old Contract Drilling Rig [Member]
Long-term Purchase Commitment [Line Items]
Term of new contract drilling rig	two years
Drilling Rig Commitments [Member]
Long-term Purchase Commitment [Line Items]
Maximum termination outstanding obligations of contracts	$ 46.3
Eagle Ford Acreage Agreement [Member]
Long-term Purchase Commitment [Line Items]
Effective date of which company entered into agreement	Sep. 01, 2012
Natural gas processing and transportation agreement	5 years
Minimum delivery commitment to avoid paying gas deficiency fee	80.00%
Transportation and processing fees under the agreement	$ 3.0	5.5
Future undiscounted minimum payments	$ 1.2
Loving County System Agreement [Member]
Long-term Purchase Commitment [Line Items]
Natural gas gathering and processing agreement	15 years
Transportation and processing fees under the agreement	$ 9.8	$ 1.8
Product Liability Contingency, Loss Exposure Not Accrued, Best Estimate	$ 11.7

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Supplemental Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Summary of current accrued liabilities
Total accrued liabilities	$ 101,460	$ 92,369
Other	3,011	2,022
Accrued evaluated and unproved and unevaluated property costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	54,273	54,586
Accrued support equipment and facilities costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	15,139	17,393
Accrued lease operating expenses [Member]
Summary of current accrued liabilities
Total accrued liabilities	16,009	7,743
Accrued interest on debt [Member]
Summary of current accrued liabilities
Total accrued liabilities	6,541	5,806
Accrued asset retirement obligations [Member]
Summary of current accrued liabilities
Total accrued liabilities	915	254
Accrued partners' share of joint interest charges [Member]
Summary of current accrued liabilities
Total accrued liabilities	$ 5,572	$ 4,565

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Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental disclosures of cash flow information
Cash paid for income taxes	$ 2,895	$ 506	$ 94
Cash paid for interest expense, net of amounts capitalized	27,464	16,154	5,269
Increase in asset retirement obligations related to mineral properties	3,817	2,510	3,843
Increase in asset retirement obligations related to support equipment and facilities	222	383	120
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures	1,775	(30,683)	32,972
(Decrease) increase in liabilities for support equipment and facilities	(588)	12,076	4,290
Issuance of restricted stock units for Board and advisor services	992	584	444
Stock-based compensation expense recognized as liability	569	79	223
Increase in liabilities for accrued cost to issue equity	343	0	0
Transfer of inventory to oil and natural gas properties	$ 395	$ 615	$ 216

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Subsidiary Guarantors (Details)	Dec. 31, 2016
Equity [Abstract]
Subsidiary ownership percentage	100.00%

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Related Party Transactions (Details) - Corporate Joint Venture [Member] $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) a joint_venture	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Number of Joint Ventures With Affiliates | joint_venture	2
Acreage Contributed By Joint Venture Partner | a	1,900
Percentage of Corporate Joint Ventures Owned BY Joint Venture Partners		50.00%
Capital Commitment To Corporate Joint Ventures	$ 14.0
Capital Contributed to Corporate Joint Ventures		$ 2.1

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Segment Reporting (Details)	12 Months Ended
	Dec. 31, 2016 USD ($) segment	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Segment Reporting Information [Line Items]
Number of business segments | segment	2
Oil and natural gas revenues	$ 291,156,000	$ 278,340,000	$ 367,712,000
Midstream services revenues	5,218,000	1,864,000	1,213,000
Realized gain on derivatives	9,286,000	77,094,000	5,022,000
Unrealized gain on derivatives	(41,238,000)	(39,265,000)	58,302,000
Expenses	441,589,000	1,124,695,000	251,918,000
Operating (loss) income	(177,167,000)	(806,662,000)	180,331,000
Total Assets	1,464,665,000	1,140,861,000	1,434,490,000
Capital expenditures	454,360,000	698,437,000	610,372,000
Depletion, depreciation and amortization	122,048,000	178,847,000	134,737,000
Impairment charge of net capitalized costs	158,633,000	801,166,000	0
Carrying value of net assets sold	31,000,000
Operating Segments [Member] | Exploration and Production Segment [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	289,512,000	277,844,000	366,191,000
Realized gain on derivatives	9,286,000	77,094,000	5,022,000
Unrealized gain on derivatives	(41,238,000)	(39,265,000)	58,302,000
Expenses	391,098,000	1,078,534,000	220,374,000
Operating (loss) income	(133,538,000)	(762,861,000)	209,141,000
Total Assets	1,098,525,000	1,000,075,000	1,388,261,000
Capital expenditures	379,881,000	622,642,000	597,351,000
Depletion, depreciation and amortization	118,400,000	176,700,000	133,100,000
Impairment charge of net capitalized costs	158,600,000	801,200,000
Operating Segments [Member] | Midstream Segment [Member]
Segment Reporting Information [Line Items]
Oil and natural gas revenues	1,644,000	496,000	1,521,000
Midstream services revenues	18,982,000	11,485,000	4,929,000
Expenses	8,254,000	5,178,000	2,703,000
Operating (loss) income	12,372,000	6,803,000	3,747,000
Total Assets	140,459,000	75,980,000	35,100,000
Capital expenditures	67,566,000	75,009,000	12,504,000
Income (loss) attributable to noncontrolling interest	400,000	300,000	17,000
Depletion, depreciation and amortization	2,700,000	1,600,000	1,200,000
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Expenses	56,001,000	50,604,000	32,557,000
Operating (loss) income	(56,001,000)	(50,604,000)	(32,557,000)
Total Assets	225,681,000	64,806,000	11,129,000
Capital expenditures	6,913,000	786,000	517,000
Depletion, depreciation and amortization	900,000	500,000	400,000
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Midstream services revenues	(13,764,000)	(9,621,000)	(3,716,000)
Expenses	(13,764,000)	$ (9,621,000)	$ (3,716,000)
Operating (loss) income	$ 0

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Subsequent Events (Narrative) (Details) $ / shares in Units, $ in Thousands			2 Months Ended	12 Months Ended
	Feb. 17, 2017 USD ($) well	Feb. 14, 2017 USD ($)	Mar. 01, 2017 USD ($) a Boe	Dec. 31, 2016 USD ($) $ / shares	Dec. 31, 2015 USD ($) $ / shares	Dec. 31, 2014 USD ($) $ / shares
Related Party Transaction [Line Items]
Ownership percentage				100.00%
Net (income) loss attributable to non-controlling interest in subsidiaries				$ 364	$ 261	$ (17)
Net (loss) income				$ 97,421	$ 679,785	$ (110,771)
Diluted (usd per share) | $ / shares				$ 1.07	$ 8.34	$ (1.56)
Subsequent Event [Member]
Related Party Transaction [Line Items]
Number of gross acres in acreage acquired | a			13,900
Number of net acres in acreage acquired | a			8,200
Product acquired (in BOE) | Boe			1,000
Total consideration given			$ 111,000
Fulcrum Delaware Water Resources [Member] | Subsequent Event [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Payments to acquire interest in joint venture		$ 2,600
San Mateo Midstream [Member] | Subsequent Event [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Ownership percentage	51.00%
Payment of initial operating capital	$ 5,100
Proceeds received in connection with formation of joint venture	176,400
Deferred performance incentives	$ 73,500
Deferred performance incentives, term	5 years
Additional amount committed to spend to expand the midstream operations and asset base	$ 140,000
Contractual obligation	273,500
San Mateo Midstream [Member] | Subsequent Event [Member] | Five Point [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Payments to acquire interest in joint venture	$ 176,400
Ownership percentage	49.00%
Proceeds received in connection with formation of joint venture	$ 171,500
San Mateo Midstream [Member] | Rustler Breaks Asset Area [Member] | Subsequent Event [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Number of wells contributed to joint venture | well	1
Contractual obligation term	15 years
San Mateo Midstream [Member] | Wolf Asset Area [Member] | Subsequent Event [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Number of wells contributed to joint venture | well	3
San Mateo Midstream [Member] | Rustler Breaks and Wolf Asset Area [Member] | Subsequent Event [Member] | Corporate Joint Venture [Member]
Related Party Transaction [Line Items]
Contractual obligation term	15 years
Adjustment [Member]
Related Party Transaction [Line Items]
Net (income) loss attributable to non-controlling interest in subsidiaries				$ 4,500
Diluted (usd per share) | $ / shares				$ 0.05
Pro Forma [Member]
Related Party Transaction [Line Items]
Net (income) loss attributable to non-controlling interest in subsidiaries				$ 4,900
Net (loss) income				$ 102,000
Diluted (usd per share) | $ / shares				$ 1.12

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Subsequent Events (Condensed Consolidated Balance Sheets - Pro-Forma) (Details) - USD ($) $ in Thousands			12 Months Ended
	Feb. 17, 2017	Feb. 14, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 31, 2016	Dec. 31, 2013
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Cash			$ 212,884	$ 16,732
Restricted cash			1,258	44,357		$ 42,100
Increase (Decrease) in Restricted Cash			(43,098)	43,098	$ 0
Oil and natural gas revenues			34,154	16,616
Joint interest billings			19,347	16,999
Other			5,167	10,794
Lease and well equipment inventory			3,045	2,022
Prepaid expenses and other assets			3,327	3,203
Total current assets			279,182	127,007
Evaluated			2,408,305	2,122,174
Unproved and unevaluated			479,736	387,504
Other property and equipment			160,795	86,387
Less accumulated depletion, depreciation and amortization			(1,864,311)	(1,583,659)
Net property and equipment			1,184,525	1,012,406
Other assets			958	1,448
Total assets			1,464,665	1,140,861	1,434,490
Accounts payable			4,674	10,966
Accrued liabilities			101,460	92,369
Royalties payable			23,988	16,493
Amounts due to affiliates			8,651	5,670
Derivative instruments			24,203	0
Advances from joint interest owners			1,700	700
Amounts due to joint ventures			4,251	2,793
Other current liabilities			578	161
Total current liabilities			169,505	136,830
Senior unsecured notes payable			573,924	391,254
Asset retirement obligations			19,725	15,166
Derivative instruments			751	0
Amounts due to joint ventures			1,771	3,956
Other long-term liabilities			7,544	2,190
Total long-term liabilities			603,715	515,072
Commitments and contingencies (Note 13)
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively			995	856
Additional paid-in capital			1,325,481	1,026,077
Accumulated deficit			(636,351)	(538,930)
Total shareholders' equity			690,125	488,003
Non-controlling interest in subsidiaries			1,320	956
Total shareholders’ equity			691,445	488,959	$ 866,541		$ 568,924
Total liabilities and shareholders’ equity			$ 1,464,665	$ 1,140,861
Ownership percentage			100.00%
Adjustment [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Cash			$ 164,340
Restricted cash			9,407
Oil and natural gas revenues			0
Joint interest billings			0
Other			0
Lease and well equipment inventory			0
Prepaid expenses and other assets			0
Total current assets			173,747
Evaluated			0
Unproved and unevaluated			0
Other property and equipment			0
Less accumulated depletion, depreciation and amortization			0
Net property and equipment			0
Total assets			173,747
Accounts payable			0
Accrued liabilities			0
Royalties payable			0
Amounts due to affiliates			0
Derivative instruments			0
Advances from joint interest owners			0
Amounts due to joint ventures			0
Other current liabilities			0
Total current liabilities			0
Senior unsecured notes payable			0
Asset retirement obligations			0
Derivative instruments			0
Amounts due to joint ventures			0
Other long-term liabilities			0
Total long-term liabilities			0
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively			0
Additional paid-in capital			124,871
Accumulated deficit			0
Total shareholders' equity			124,871
Non-controlling interest in subsidiaries			48,876
Total shareholders’ equity			173,747
Total liabilities and shareholders’ equity			173,747
Pro Forma [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Cash			377,224
Restricted cash			10,665
Oil and natural gas revenues			34,154
Joint interest billings			19,347
Other			5,167
Lease and well equipment inventory			3,045
Prepaid expenses and other assets			3,327
Total current assets			452,929
Evaluated			2,408,305
Unproved and unevaluated			479,736
Other property and equipment			160,795
Less accumulated depletion, depreciation and amortization			(1,864,311)
Net property and equipment			1,184,525
Other assets			958
Total assets			1,638,412
Accounts payable			4,674
Accrued liabilities			101,460
Royalties payable			23,988
Amounts due to affiliates			8,651
Derivative instruments			24,203
Advances from joint interest owners			1,700
Amounts due to joint ventures			4,251
Other current liabilities			578
Total current liabilities			169,505
Senior unsecured notes payable			573,924
Asset retirement obligations			19,725
Derivative instruments			751
Amounts due to joint ventures			1,771
Other long-term liabilities			7,544
Total long-term liabilities			603,715
Commitments and contingencies (Note 13)
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively			995
Additional paid-in capital			1,450,352
Accumulated deficit			(636,351)
Total shareholders' equity			814,996
Non-controlling interest in subsidiaries			50,196
Total shareholders’ equity			865,192
Total liabilities and shareholders’ equity			$ 1,638,412
San Mateo Midstream [Member] | Corporate Joint Venture [Member] | Subsequent Event [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Restricted cash	$ 10,000
Proceeds received in connection with formation of joint venture	$ 176,400
Ownership percentage	51.00%
San Mateo Midstream [Member] | Corporate Joint Venture [Member] | Subsequent Event [Member] | Five Point [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Proceeds received in connection with formation of joint venture	$ 171,500
Ownership percentage	49.00%
Payments to acquire interest in joint venture	$ 176,400
Fulcrum Delaware Water Resources [Member] | Corporate Joint Venture [Member] | Subsequent Event [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Increase (Decrease) in Restricted Cash	$ (600)	$ (600)
Payments to acquire interest in joint venture		$ 2,600

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Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash	$ 212,884		$ 16,732
Restricted cash	1,258	$ 42,100	44,357
Oil and natural gas revenues	34,154		16,616
Joint interest billings	19,347		16,999
Other	5,167		10,794
Derivative instruments	0		16,284
Lease and well equipment inventory	3,045		2,022
Prepaid expenses and other assets	3,327		3,203
Total current assets	279,182		127,007
Evaluated	2,408,305		2,122,174
Unproved and unevaluated	479,736		387,504
Other property and equipment	160,795		86,387
Less accumulated depletion, depreciation and amortization	(1,864,311)		(1,583,659)
Net property and equipment	1,184,525		1,012,406
Other assets	958		1,448
Total assets	1,464,665		1,140,861	$ 1,434,490
Accounts payable	4,674		10,966
Accrued liabilities	101,460		92,369
Royalties payable	23,988		16,493
Amounts due to affiliates	8,651		5,670
Derivative instruments	24,203		0
Advances from joint interest owners	1,700		700
Deferred gain on sale of property, current	0		4,830
Amounts due to joint ventures	4,251		2,793
Other current liabilities	578		161
Total current liabilities	169,505		136,830
Senior unsecured notes payable	573,924		391,254
Asset retirement obligations	19,725		15,166
Derivative instruments	751		0
Amounts due to joint ventures	1,771		3,956
Deferred gain on sale of property, non-current	0		102,506
Other long-term liabilities	7,544		2,190
Total long-term liabilities	603,715		515,072
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	995		856
Additional paid-in capital	1,325,481		1,026,077
Accumulated deficit	(636,351)		(538,930)
Total shareholders' equity	690,125		488,003
Non-controlling interest in subsidiaries	1,320		956
Total shareholders’ equity	691,445		488,959	$ 866,541	$ 568,924
Total liabilities and shareholders’ equity	1,464,665		1,140,861
Adjustment [Member]
Cash	164,340
Restricted cash	9,407
Oil and natural gas revenues	0
Joint interest billings	0
Other	0
Lease and well equipment inventory	0
Prepaid expenses and other assets	0
Total current assets	173,747
Evaluated	0
Unproved and unevaluated	0
Other property and equipment	0
Less accumulated depletion, depreciation and amortization	0
Net property and equipment	0
Total assets	173,747
Accounts payable	0
Accrued liabilities	0
Royalties payable	0
Amounts due to affiliates	0
Derivative instruments	0
Advances from joint interest owners	0
Amounts due to joint ventures	0
Other current liabilities	0
Total current liabilities	0
Senior unsecured notes payable	0
Asset retirement obligations	0
Derivative instruments	0
Amounts due to joint ventures	0
Other long-term liabilities	0
Total long-term liabilities	0
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively	0
Additional paid-in capital	124,871
Accumulated deficit	0
Total shareholders' equity	124,871
Non-controlling interest in subsidiaries	48,876
Total shareholders’ equity	173,747
Total liabilities and shareholders’ equity	173,747
Adjustment [Member] | Consolidation, Eliminations [Member]
Intercompany receivable	(332,453)		(317,964)
Other	0		0
Net property and equipment	0		0
Other assets			0
Investments in subsidiaries	(947,037)		(604,816)
Total assets	(1,279,490)		(922,780)
Intercompany payable	(332,453)		(317,964)
Other current liabilities	0		0
Senior unsecured notes payable	0		0
Other long-term liabilities	0		0
Total shareholders' equity	(947,037)		(604,816)
Non-controlling interest in subsidiaries	0		0
Total liabilities and shareholders’ equity	(1,279,490)		(922,780)
Adjustment [Member] | Parent
Intercompany receivable	316,791		304,573
Other	101,102		289
Net property and equipment	33		0
Other assets	0		0
Investments in subsidiaries	856,762		584,461
Total assets	1,274,688		889,323
Intercompany payable	0		0
Other current liabilities	9,265		10,066
Senior unsecured notes payable	573,924		391,254
Other long-term liabilities	1,374		0
Total shareholders' equity	690,125		488,003
Non-controlling interest in subsidiaries	0		0
Total liabilities and shareholders’ equity	1,274,688		889,323
Adjustment [Member] | Non-Guarantor Subsidiaries
Intercompany receivable	3,571		1,463
Other	4,242		1,141
Net property and equipment	113,107		47,535
Other assets	0		0
Investments in subsidiaries	0		0
Total assets	120,920		50,139
Intercompany payable	12,091		11,928
Other current liabilities	16,632		16,557
Senior unsecured notes payable	0		0
Other long-term liabilities	602		343
Total shareholders' equity	90,275		20,355
Non-controlling interest in subsidiaries	1,320		956
Total liabilities and shareholders’ equity	120,920		50,139
Adjustment [Member] | Existing Guarantor Subsidiaries
Intercompany receivable	12,091		11,928
Other	173,838		125,577
Net property and equipment	1,071,385		964,871
Other assets	958		1,448
Investments in subsidiaries	90,275		20,355
Total assets	1,348,547		1,124,179
Intercompany payable	320,362		306,036
Other current liabilities	143,608		110,207
Senior unsecured notes payable	0		0
Other long-term liabilities	27,815		123,475
Total shareholders' equity	856,762		584,461
Non-controlling interest in subsidiaries	0		0
Total liabilities and shareholders’ equity	1,348,547		1,124,179
Adjustment [Member] | Consolidated Entity
Intercompany receivable	0		0
Other	279,182		127,007
Net property and equipment	1,184,525		1,012,406
Other assets	958		1,448
Investments in subsidiaries	0		0
Total assets	1,464,665		1,140,861
Intercompany payable	0		0
Other current liabilities	169,505		136,830
Senior unsecured notes payable	573,924		391,254
Other long-term liabilities	29,791		123,818
Total shareholders' equity	690,125		488,003
Non-controlling interest in subsidiaries	1,320		956
Total liabilities and shareholders’ equity	$ 1,464,665		$ 1,140,861

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Condensed Consolidated Statements Condensed Consolidated Statement of Operations (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and natural gas revenues	$ 291,156	$ 278,340	$ 367,712
Midstream services revenues	5,218	1,864	1,213
Third-party midstream services revenues	9,286	77,094	5,022
Unrealized (loss) gain on derivatives	(41,238)	(39,265)	58,302
Total revenues	264,422	318,033	432,249
Production taxes and marketing	43,046	35,650	33,172
Lease operating	56,202	54,704	49,945
Plant and other midstream services operating	5,389	3,489	1,408
Depletion, depreciation and amortization	122,048	178,847	134,737
Accretion of asset retirement obligations	1,182	734	504
Full-cost ceiling impairment	158,633	801,166	0
General and administrative	55,089	50,105	32,152
Total expenses	441,589	1,124,695	251,918
Operating (loss) income	(177,167)	(806,662)	180,331
Net gain on asset sales and inventory impairment	107,277	908	0
Interest expense	(28,199)	(21,754)	(5,334)
Interest and Other Income (Expense)	(4)	616	132
Total other income (expense)	79,074	(20,230)	(5,202)
(Loss) income before income taxes	(98,093)	(826,892)	175,129
Current	(1,036)	2,959	133
Deferred	0	(150,327)	64,242
Total income tax (benefit) provision	(1,036)	(147,368)	64,375
Net (loss) income	(97,057)	(679,524)	110,754
Net (income) loss attributable to non-controlling interest in subsidiaries	(364)	(261)	17
Net (loss) income attributable to Matador Resources Company shareholders	$ (97,421)	$ (679,785)	$ 110,771
Basic (usd per share)	$ (1.07)	$ (8.34)	$ 1.58
Diluted (usd per share)	$ (1.07)	$ (8.34)	$ 1.56
Diluted	91,273	81,537	70,906
Basic	91,273	81,537	70,229
Adjustment [Member]
Net (income) loss attributable to non-controlling interest in subsidiaries	$ (4,500)
Diluted (usd per share)	$ (0.05)
Consolidation, Eliminations [Member]
Midstream services revenues	$ (13,764)	$ (9,621)	$ (3,716)
Total expenses	(13,764)	(9,621)	(3,716)
Operating (loss) income	0
Consolidation, Eliminations [Member] | Adjustment [Member]
Total revenues	(10,708)	(4,344)	0
Total expenses	(10,708)	(4,344)	0
Operating (loss) income	0	0	0
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	0	0	0
Interest and Other Income (Expense)	0	0	0
(Loss) earnings in subsidiaries	54,539	656,240	(112,814)
(Loss) income before income taxes	54,539	656,240	(112,814)
Total income tax (benefit) provision	0	0	0
Net (income) loss attributable to non-controlling interest in subsidiaries	0	0	0
Net (loss) income attributable to Matador Resources Company shareholders	54,539	656,240	(112,814)
Parent | Adjustment [Member]
Total revenues	0	0	0
Total expenses	5,319	5,739	3,389
Operating (loss) income	(5,319)	(5,739)	(3,389)
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	(28,199)	(20,511)	0
Interest and Other Income (Expense)	0	0	0
(Loss) earnings in subsidiaries	(64,349)	(658,698)	112,908
(Loss) income before income taxes	(97,867)	(684,948)	109,519
Total income tax (benefit) provision	(446)	(5,163)	(1,252)
Net (income) loss attributable to non-controlling interest in subsidiaries	0	0	0
Net (loss) income attributable to Matador Resources Company shareholders	(97,421)	(679,785)	110,771
Non-Guarantor Subsidiaries | Adjustment [Member]
Total revenues	17,302	6,310	0
Total expenses	7,031	2,944	111
Operating (loss) income	10,271	3,366	(111)
Net gain on asset sales and inventory impairment	0	0	0
Interest expense	0	0	0
Interest and Other Income (Expense)	0	0	0
(Loss) earnings in subsidiaries	0	0	0
(Loss) income before income taxes	10,271	3,366	(111)
Total income tax (benefit) provision	97	647	0
Net (income) loss attributable to non-controlling interest in subsidiaries	(364)	(261)	17
Net (loss) income attributable to Matador Resources Company shareholders	9,810	2,458	(94)
Existing Guarantor Subsidiaries | Adjustment [Member]
Total revenues	257,828	316,067	432,249
Total expenses	439,947	1,120,356	248,418
Operating (loss) income	(182,119)	(804,289)	183,831
Net gain on asset sales and inventory impairment	107,277	908	0
Interest expense	0	(1,243)	(5,334)
Interest and Other Income (Expense)	(4)	616	132
(Loss) earnings in subsidiaries	9,810	2,458	(94)
(Loss) income before income taxes	(65,036)	(801,550)	178,535
Total income tax (benefit) provision	(687)	(142,852)	65,627
Net (income) loss attributable to non-controlling interest in subsidiaries	0	0	0
Net (loss) income attributable to Matador Resources Company shareholders	(64,349)	(658,698)	112,908
Consolidated Entity | Adjustment [Member]
Total revenues	264,422	318,033	432,249
Total expenses	441,589	1,124,695	251,918
Operating (loss) income	(177,167)	(806,662)	180,331
Net gain on asset sales and inventory impairment	107,277	908	0
Interest expense	(28,199)	(21,754)	(5,334)
Interest and Other Income (Expense)	(4)	616	132
(Loss) earnings in subsidiaries	0	0	0
(Loss) income before income taxes	(98,093)	(826,892)	175,129
Total income tax (benefit) provision	(1,036)	(147,368)	64,375
Net (income) loss attributable to non-controlling interest in subsidiaries	(364)	(261)	17
Net (loss) income attributable to Matador Resources Company shareholders	$ (97,421)	$ (679,785)	$ 110,771

XML

Condensed Consolidated Statements Condensed Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands			12 Months Ended
	Apr. 21, 2015	May 29, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net (loss) income			$ (97,057)	$ (679,524)	$ 110,754
Unrealized (loss) gain on derivatives			(41,238)	(39,265)	58,302
Depletion, depreciation and amortization			122,048	178,847	134,737
Accretion of asset retirement obligations			1,182	734	504
Full-cost ceiling impairment			158,633	801,166	0
Stock-based compensation expense			12,362	9,450	5,524
Deferred income tax (benefit) provision			0	(150,327)	64,242
Amortization of debt issuance cost			1,148	852	0
Net gain on asset sales and inventory impairment			(107,277)	(908)	0
Accounts receivable			(14,259)	3,633	(13,318)
Lease and well equipment inventory			(700)	(180)	(211)
Prepaid expenses			(124)	(544)	(783)
Other assets			490	(552)	1,212
Accounts payable, accrued liabilities and other current liabilities			6,611	1,375	607
Royalties payable			7,495	1,654	6,663
Advances from joint interest owners			1,000	700	0
Income taxes payable			(2,848)	2,405	39
Other long-term liabilities			4,144	489	(187)
Net cash provided by operating activities			134,086	208,535	251,481
Proceeds from sale of assets			5,173	139,836	79
Oil and natural gas properties capital expenditures			(379,067)	(432,715)	(560,849)
Expenditures for other property and equipment			(74,845)	(64,499)	(9,152)
Business combination, net of cash acquired			0	(24,028)	0
Restricted cash			43,098	(43,098)	0
Restricted cash in less-than-wholly-owned subsidiaries			1	(650)	(609)
Net cash used in investing activities			(405,640)	(425,154)	(570,531)
Repayments of borrowings			(120,000)	(476,982)	(180,000)
Borrowings under Credit Agreement			120,000	125,000	320,000
Proceeds from issuance of common stock	$ 187,600	$ 181,300	288,510	188,720	181,875
Proceeds from issuance of senior unsecured notes			184,625	400,000	0
Cost to issue equity			(847)	(1,158)	(590)
Cost to issue senior unsecured notes			(2,734)	(9,598)	0
Proceeds from stock options exercised			100	10	43
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries			0	562	150
Taxes paid related to net share settlement of stock-based compensation			(1,948)	(1,610)	(308)
Net cash provided by financing activities			467,706	224,944	321,170
Increase in cash			196,152	8,325	2,120
Cash at beginning of year			16,732	8,407	6,287
Cash at end of year			212,884	16,732	8,407
Adjustment [Member] | Consolidation, Eliminations [Member]
Net cash provided by operating activities			0	0	0
Net cash used in investing activities			384,801	563,505	173,949
Net cash provided by financing activities			(384,801)	(563,505)	(173,949)
Increase in cash			0	0	0
Cash at beginning of year			0	0	0
Cash at end of year			0	0	0
Adjustment [Member] | Parent
Net cash provided by operating activities			(45,215)	(31,271)	(8,607)
Net cash used in investing activities			(324,724)	(546,715)	(172,749)
Net cash provided by financing activities			469,654	577,973	181,328
Increase in cash			99,715	(13)	(28)
Cash at beginning of year			80	93	121
Cash at end of year			99,795	80	93
Adjustment [Member] | Non-Guarantor Subsidiaries
Net cash provided by operating activities			6,694	13,916	431
Net cash used in investing activities			(64,683)	(31,101)	(1,763)
Net cash provided by financing activities			60,110	17,353	1,350
Increase in cash			2,121	168	18
Cash at beginning of year			186	18	0
Cash at end of year			2,307	186	18
Adjustment [Member] | Existing Guarantor Subsidiaries
Net cash provided by operating activities			172,607	225,890	259,657
Net cash used in investing activities			(401,034)	(410,843)	(569,968)
Net cash provided by financing activities			322,743	193,123	312,441
Increase in cash			94,316	8,170	2,130
Cash at beginning of year			16,466	8,296	6,166
Cash at end of year			110,782	16,466	8,296
Adjustment [Member] | Consolidated Entity
Net cash provided by operating activities			134,086	208,535	251,481
Net cash used in investing activities			(405,640)	(425,154)	(570,531)
Net cash provided by financing activities			467,706	224,944	321,170
Increase in cash			196,152	8,325	2,120
Cash at beginning of year			16,732	8,407	6,287
Cash at end of year			$ 212,884	$ 16,732	$ 8,407