Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2018	Aug. 01, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	Matador Resources Co
Entity Central Index Key	0001520006
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		116,365,216

Condensed Consolidated Balance Sheets - Unaudited - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash	$ 122,450	$ 96,505
Restricted cash	21,063	5,977
Accounts receivable
Oil and natural gas revenues	74,771	65,962
Joint interest billings	71,041	67,225
Other	4,726	8,031
Derivative instruments	5,875	1,190
Lease and well equipment inventory	12,557	5,993
Prepaid expenses and other assets	8,454	6,287
Total current assets	320,937	257,170
Oil and natural gas properties, full-cost method
Evaluated	3,338,515	3,004,770
Unproved and unevaluated	692,544	637,396
Midstream and other property and equipment	360,971	281,096
Less accumulated depletion, depreciation and amortization	(2,164,013)	(2,041,806)
Net property and equipment	2,228,017	1,881,456
Other assets	6,893	7,064
Total assets	2,555,847	2,145,690
Current liabilities
Accounts payable	25,278	11,757
Accrued liabilities	133,365	174,348
Royalties payable	69,751	61,358
Amounts due to affiliates	8,108	10,302
Derivative instruments	4,016	16,429
Advances from joint interest owners	18,814	2,789
Amounts due to joint ventures	3,373	4,873
Other current liabilities	893	750
Total current liabilities	263,598	282,606
Long-term liabilities
Senior unsecured notes payable	574,164	574,073
Asset retirement obligations	26,890	25,080
Amounts due to joint ventures	5,253	0
Other long-term liabilities	6,194	6,385
Total long-term liabilities	612,501	605,538
Commitments and contingencies
Shareholders’ equity
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,461,171 and 108,513,597 shares issued; and 116,357,739 and 108,510,160 shares outstanding, respectively	1,165	1,085
Additional paid-in capital	1,916,821	1,666,024
Accumulated deficit	(390,784)	(510,484)
Treasury stock, at cost, 103,432 and 3,437 shares, respectively	(2,670)	(69)
Total Matador Resources Company shareholders’ equity	1,524,532	1,156,556
Non-controlling interest in subsidiaries	155,216	100,990
Total shareholders’ equity	1,679,748	1,257,546
Total liabilities and shareholders’ equity	$ 2,555,847	$ 2,145,690

Condensed Consolidated Balance Sheets (Parenthetical) - Unaudited - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	160,000,000	120,000,000
Common stock, shares issued	116,461,171	108,513,597
Common stock, shares outstanding	116,357,739	108,510,160
Treasury stock, shares	103,432	3,437

Condensed Consolidated Statements of Operations - Unaudited - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues
Oil and natural gas revenues	$ 209,019	$ 113,764	$ 390,973	$ 228,611
Third-party midstream services revenues	3,407	2,099	6,475	3,654
Realized (loss) gain on derivatives	(2,488)	558	(6,746)	(1,661)
Unrealized gain on derivatives	1,429	13,190	11,845	33,821
Total revenues	211,367	129,611	402,547	264,425
Expenses
Production taxes, transportation and processing	20,110	12,875	37,901	24,682
Lease operating	25,006	16,040	47,154	31,797
Plant and other midstream services operating	5,676	2,942	9,896	5,283
Depletion, depreciation and amortization	66,838	41,274	122,207	75,266
Accretion of asset retirement obligations	375	314	739	614
General and administrative	19,369	17,177	37,295	33,515
Total expenses	137,374	90,622	255,192	171,157
Operating income	73,993	38,989	147,355	93,268
Other income (expense)
Net gain on asset sales and inventory impairment	0	0	0	7
Interest expense	(8,004)	(9,224)	(16,495)	(17,679)
Other (expense) income	(352)	1,922	(299)	1,991
Total other expense	(8,356)	(7,302)	(16,794)	(15,681)
Net income	65,637	31,687	130,561	77,587
Net income attributable to non-controlling interest in subsidiaries	5,831	3,178	10,861	5,094
Net income attributable to Matador Resources Company shareholders	$ 59,806	$ 28,509	$ 119,700	$ 72,493
Earnings per common share
Basic (in dollars per share)	$ 0.53	$ 0.28	$ 1.08	$ 0.72
Diluted (in dollars per share)	$ 0.53	$ 0.28	$ 1.08	$ 0.72
Weighted average common shares outstanding
Basic (shares)	112,706	100,211	110,809	100,005
Diluted (shares)	113,056	100,227	111,280	100,455

Condensed Consolidated Statement of Changes in Shareholders' Equity - Unaudited - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Common Stock	Additional paid-in capital	Accumulated deficit	Treasury Stock	Total shareholders’ equity attributable to Matador Resources Company	Non-controlling interest in subsidiaries	Convertible Preferred Stock [Member]	Convertible Preferred Stock [Member] Additional paid-in capital	Convertible Preferred Stock [Member] Total shareholders’ equity attributable to Matador Resources Company
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		717,000
Stock Issued During Period, Value, Share-based Compensation, Gross	$ 0	$ 7	$ (7)			$ 0
Beginning Balance, shares at Dec. 31, 2017	108,510,160	108,514,000			3,000
Beginning balance at Dec. 31, 2017	$ 1,257,546	$ 1,085	1,666,024	$ (510,484)	$ (69)	1,156,556	$ 100,990
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock pursuant to employee stock compensation plan, shares		7,000,000
Issuance of common stock pursuant to employee stock compensation plan		$ 70						$ 226,612	$ 226,542	$ 226,612
Common stock issued to Board members and advisors, shares		76,000
Issuance of common stock pursuant to directors’ and advisors’ compensation plan	0	$ 1	(1)			0
Stock-based compensation expense related to equity-based awards including amounts capitalized	11,327		11,327			11,327
Stock options exercised, shares		154,000
Stock options exercised, net of options forfeited in net share settlements	(1,616)	$ 2	(1,618)			(1,616)
Restricted stock forfeited, shares					100,000
Restricted stock forfeited	(2,601)				$ (2,601)	(2,601)
Contributions related to formation of Joint Venture (see Note 6)	14,700		14,700			14,700	0
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	53,900						53,900
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(10,535)						(10,535)
Current period net income	$ 130,561			119,700		119,700	10,861
Ending Balance, shares at Jun. 30, 2018	116,357,739	116,461,000			103,000
Ending balance at Jun. 30, 2018	$ 1,679,748	$ 1,165	1,916,821	$ (390,784)	$ (2,670)	1,524,532	$ 155,216
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 146		$ 146			$ 146

Condensed Consolidated Statements of Cash Flows - Unaudited - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Statement of Cash Flows [Abstract]
Current period net income	$ 130,561	$ 77,587
Adjustments to reconcile net income to net cash provided by operating activities
Unrealized gain on derivatives	(11,845)	(33,821)
Depletion, depreciation and amortization	122,207	75,266
Accretion of asset retirement obligations	739	614
Stock-based compensation expense	8,945	11,192
Amortization of debt issuance cost	411	64
Net gain on asset sales and inventory impairment	0	(7)
Changes in operating assets and liabilities
Accounts receivable	(9,321)	(25,642)
Lease and well equipment inventory	(8,611)	(140)
Prepaid expenses	(2,167)	(2,619)
Other assets	(149)	165
Accounts payable, accrued liabilities and other current liabilities	(883)	4,442
Royalties payable	8,393	11,435
Advances from joint interest owners	16,025	3,768
Other long-term liabilities	(97)	(1,062)
Net cash provided by operating activities	254,208	121,242
Investing activities
Oil and natural gas properties capital expenditures	(421,595)	(328,929)
Expenditures for midstream and other property and equipment	(79,560)	(41,743)
Proceeds from sale of assets	7,593	977
Net cash used in investing activities	(493,562)	(369,695)
Financing activities
Repayments of borrowings	45,000	0
Borrowings under Credit Agreement	45,000	0
Proceeds from issuance of common stock	226,612	0
Cost to issue equity	73	0
Proceeds from stock options exercised	464	2,201
Contributions related to formation of Joint Venture	14,700	171,500
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries	53,900	14,700
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(10,535)	(1,960)
Taxes paid related to net share settlement of stock-based compensation	(4,683)	(2,970)
Purchase of non-controlling interest of less-than-wholly-owned subsidiary	0	(2,653)
Net cash provided by financing activities	280,385	180,818
Increase (decrease) in cash and restricted cash	41,031	(67,635)
Cash and restricted cash at beginning of period	102,482	214,142
Cash and restricted cash at end of period	$ 143,513	$ 146,507

Nature of Operations	6 Months Ended
Nature of Operations	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS	NATURE OF OPERATIONS Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties.

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The interim unaudited condensed consolidated financial statements of the Company have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “Annual Report”) filed with the SEC. The Company consolidates certain subsidiaries and joint ventures that are less than wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification, Consolidation (Topic 810). The Company proportionately consolidates certain joint ventures that are less than wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all normal, recurring adjustments that are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of June 30, 2018. Amounts as of December 31, 2017 are derived from the Company’s audited consolidated financial statements included in the Annual Report.

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

Change in Accounting Principles

During the first quarter of 2018, the Company adopted Accounting Standards Codification, Revenue from Contracts with Customers (Topic 606) (“ASC 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. The Company adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on the Company’s consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows.

Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

The Company enters into contracts with customers to sell its oil and natural gas production. With the adoption of ASC 606, revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas and transports the natural gas via pipeline to natural gas processing plants where, if necessary, natural gas liquid (“NGL”) products are extracted. The NGL products and remaining residue gas are then sold by the purchaser, or if the Company elects to repurchase the natural gas, the Company sells the natural gas to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations.

The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract.

The Company determined the impact to its consolidated financial statements as a result of adoption of ASC 606 was a $2.6 million and $4.8 million decrease in oil and natural gas revenues and a $2.6 million and $4.8 million decrease in production taxes, transportation and processing expenses for the three and six months ended June 30, 2018, respectively, which was not material. As a result of adoption of this standard, the Company is now required to disclose the following information regarding total revenues and revenues from contracts with customers on a disaggregated basis for the three and six months ended June 30, 2018 (in thousands).



	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Revenues from contracts with customers	$	212,426		$	397,448
Realized loss on derivatives	(2,488		)	(6,746		)
Unrealized gain on derivatives	1,429			11,845
Total revenues	$	211,367		$	402,547



	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Oil revenues	$	166,271	$	314,430
Natural gas revenues	42,748		76,543
Third-party midstream services revenues	3,407		6,475
Total revenues from contracts with customers	$	212,426	$	397,448

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

During the first quarter of 2018, the Company adopted Accounting Standards Update (“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. The Company adopted ASU 2016-18 effective January 1, 2018 and determined that the adoption of this ASU changed the presentation of its beginning and ending cash balances and eliminated the presentation of changes in restricted cash balances from investing activities in its consolidated statements of cash flows. The Company adopted the new guidance using the retrospective transition method; as a result, approximately $6.0 million and $1.3 million of restricted cash was added to the beginning cash balance for the six months ended June 30, 2018 and 2017, respectively.

During the first quarter of 2018, the Company adopted 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. The Company adopted ASU 2017-01 prospectively, which did not have a material impact on its consolidated financial statements.

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter that determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For both the three and six months ended June 30, 2018 and 2017, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and, as a result, no impairment charge was necessary.

The Company capitalized approximately $6.8 million and $5.2 million of its general and administrative costs for the three months ended June 30, 2018 and 2017, respectively, and approximately $2.6 million and $1.9 million of its interest expense for the three months ended June 30, 2018 and 2017, respectively. The Company capitalized approximately $14.1 million and $10.8 million of its general and administrative costs for the six months ended June 30, 2018 and 2017, respectively, and approximately $4.5 million and $3.2 million of its interest expense for the six months ended June 30, 2018 and 2017, respectively.

Earnings (Loss) Per Common Share

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

The following table sets forth the computation of diluted weighted average common shares outstanding for the three and six months ended June 30, 2018 and 2017 (in thousands).



	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Weighted average common shares outstanding
Basic	112,706	100,211	110,809	100,005
Dilutive effect of options and restricted stock units	350	16	471	450
Diluted weighted average common shares outstanding	113,056	100,227	111,280	100,455

Recent Accounting Pronouncements

Leases. In February 2016, the Financial Accounting Standards Board (“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. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt these ASUs as of January 1, 2019.

Stock Compensation. In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. This ASU extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Currently, the Company accounts for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards is recalculated each reporting period. Upon adoption, all such awards will be measured at fair value on the grant date and the resulting expense will be recognized on a straight-line basis over the awards’ vesting period. This ASU is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. The Company expects to adopt this ASU as of January 1, 2019 and does not anticipate this ASU will have a material impact to the Company’s consolidated financial statements.

Asset Retirement Obligations

6 Months Ended

Jun. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2018 (in thousands).




Beginning asset retirement obligations	$	26,256
Liabilities incurred during period	1,589
Liabilities settled during period	(459		)
Accretion expense	739
Ending asset retirement obligations	28,125
Less: current asset retirement obligations⁽¹⁾	(1,235		)
Long-term asset retirement obligations	$	26,890

_______________


(1)	Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at June 30, 2018.

Debt	6 Months Ended
Debt	Jun. 30, 2018
Debt Disclosure [Abstract]
DEBT	At June 30, 2018 and August 1, 2018, the Company had $575.0 million of outstanding 6.875% senior notes due 2023 (the “Notes”), no borrowings outstanding under the Company’s revolving credit agreement (the “Credit Agreement”) and approximately $3.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. Credit Agreement The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2018, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2017, and as a result, on March 5, 2018, the borrowing base was increased to $725.0 million. This March 2018 redetermination constituted the regularly scheduled May 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million and the maximum facility amount remained at $500.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020. The Company believes that it was in compliance with the terms of the Credit Agreement at June 30, 2018. Senior Unsecured Notes On April 14, 2015 and December 9, 2016, the Company issued $400.0 million and $175.0 million, respectively, of Notes. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

Income Taxes	6 Months Ended
Income Taxes	Jun. 30, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The Company’s deferred tax assets exceeded its deferred tax liabilities at June 30, 2018 due to the deferred tax assets generated by full-cost ceiling impairment charges recorded in prior periods. The Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at June 30, 2018 due to uncertainties regarding the future realization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits is more likely than not to be utilized.

Equity	6 Months Ended
Equity	Jun. 30, 2018
Equity [Abstract]
EQUITY	ased Compensation In February 2018, the Company granted awards of 667,488 shares of restricted stock and options to purchase 563,408 shares of the Company’s common stock at an exercise price of $29.68 per share to certain of its employees. The fair value of these awards was approximately $26.9 million. All of these awards vest ratably over three years. Performance Incentive In connection with the formation of San Mateo in 2017, the Company has the ability to earn a total of $73.5 million in performance incentives to be paid by its joint venture partner, a subsidiary of Five Point Energy LLC (“Five Point”), over a five-year period. The Company earned, and Five Point paid to the Company, $14.7 million in performance incentives during the six months ended June 30, 2018, and the Company may earn an additional $58.8 million in performance incentives over the next four years. These performance incentives are recorded as an increase to additional paid-in capital when received.

Derivative Financial Instruments

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

At June 30, 2018, the Company had various costless collar, three-way costless collar and swap 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 and fixed price for the swaps. Each contract is set to expire at varying times during 2018 and 2019.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at June 30, 2018.



Commodity	Calculation Period	Notional Quantity (Bbl or MMBtu)	Weighted Average Price Floor ($/Bbl or $/MMBtu)		Weighted Average Price Ceiling ($/Bbl or $/MMBtu)		Fair Value of Asset (Liability) (thousands)
Oil - WTI⁽¹⁾	07/01/2018 - 12/31/2018	1,440,000	$	44.27	$	60.29	$	(15,986	)
Oil - WTI⁽¹⁾	01/01/2019 - 12/31/2019	2,400,000	$	50.00	$	64.75	(12,208		)
Oil - LLS⁽²⁾	07/01/2018 - 12/31/2018	360,000	$	45.00	$	63.05	(4,381		)
Natural Gas	07/01/2018 - 12/31/2018	8,400,000	$	2.58	$	3.67	79
Total open costless collar contracts							$	(32,496	)

_____________________

(1) NYMEX West Texas Intermediate crude oil.

(2) Argus Louisiana Light Sweet crude oil.

The following is a summary of the Company’s open three-way costless collar contracts for oil at June 30, 2018. Open three-way costless collars consist of a long put (the floor), a short call (the ceiling) and a long call that limits losses on the upside.



Commodity	Calculation Period	Notional Quantity (Bbl)	Weighted Average Price Floor ($/Bbl)		Weighted Average Price, Short Call ($/Bbl)		Weighted Average Price, Long Call ($/Bbl)		Fair Value of Asset (Liability) (thousands)
Oil - WTI⁽¹⁾	07/01/2018 - 12/31/2018	960,000	$	50.08	$	63.50	$	66.68	$	(2,249	)
Total open three-way costless collar contracts									$	(2,249	)

_____________________

(1) NYMEX West Texas Intermediate crude oil.

The following is a summary of the Company’s open basis swap contracts for oil at June 30, 2018.



Commodity	Calculation Period	Notional Quantity (Bbl)	Fixed Price ($/Bbl)			Fair Value of Asset (Liability) (thousands)
Oil Basis Swaps	07/01/2018 - 12/31/2018	2,610,000	$	(1.02	)	$	31,351
Total open swap contracts						$	31,351

Total open derivative financial instruments						$	(3,394	)

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

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 (in thousands).



Derivative Instruments	Gross amounts recognized			Gross amounts netted in the condensed consolidated balance sheets			Net amounts presented in the condensed consolidated balance sheets
June 30, 2018
Current assets	$	101,679		$	(95,804	)	$	5,875
Other assets	2,749			(2,749		)	—
Current liabilities	(99,820		)	95,804			(4,016		)
Other liabilities	(8,002		)	2,749			(5,253		)
Total	$	(3,394	)	$	—		$	(3,394	)
December 31, 2017
Current assets	$	131,092		$	(129,902	)	$	1,190
Current liabilities	(146,331		)	129,902			(16,429		)
Total	$	(15,239	)	$	—		$	(15,239	)

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



		Three Months Ended June 30,						Six Months Ended June 30,
Type of Instrument	Location in Condensed Consolidated Statement of Operations	2018			2017			2018			2017
Derivative Instrument
Oil	Revenues: Realized (loss) gain on derivatives	$	(2,488	)	$	581		$	(6,797	)	$	(1,053	)
Natural Gas	Revenues: Realized (loss) gain on derivatives	—			(23		)	51			(608		)
Realized (loss) gain on derivatives		(2,488		)	558			(6,746		)	(1,661		)
Oil	Revenues: Unrealized gain on derivatives	1,829			10,643			12,956			28,422
Natural Gas	Revenues: Unrealized (loss) gain on derivatives	(400		)	2,547			(1,111		)	5,399
Unrealized gain on derivatives		1,429			13,190			11,845			33,821
Total		$	(1,059	)	$	13,748		$	5,099		$	32,160

Fair Value Measurements

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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


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

Level 2

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


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

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

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2018 and December 31, 2017 (in thousands).



	Fair Value Measurements at June 30, 2018 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Natural gas derivatives	$	—	$	79		$	—	$	79
Oil derivatives and basis swaps	—		(3,473		)	—		(3,473		)
Total	$	—	$	(3,394	)	$	—	$	(3,394	)



	Fair Value Measurements at December 31, 2017 using
Description	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Natural gas derivatives	$	—	$	1,190		$	—	$	1,190
Oil derivatives and basis swaps	—		(16,429		)	—		(16,429		)
Total	$	—	$	(15,239	)	$	—	$	(15,239	)

Additional disclosures related to derivative financial instruments are provided in Note 7.

Other Fair Value Measurements

At June 30, 2018 and December 31, 2017, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses and other assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities.

At June 30, 2018 and December 31, 2017, the fair value of the Notes was $603.4 million and $614.1 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	Processing, Transportation and Salt Water Disposal Commitments Delaware Basin — Loving County, Texas Natural Gas Processing In late 2015, the Company entered into a 15-year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s minimum commitment. If the Company ceased operations in this area at June 30, 2018, the total deficiency fee required to be paid would be approximately $10.9 million. In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating that year’s natural gas deficiency. The Company paid approximately $4.0 million and $3.7 million in natural gas processing and gathering fees under this agreement during the three months ended June 30, 2018 and 2017, respectively, and $7.4 million and $6.8 million in natural gas processing and gathering fees under this agreement during the six months ended June 30, 2018 and 2017, respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants. Delaware Basin — Eddy County, New Mexico Natural Gas Transportation In late 2017, the Company entered into an 18-year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”) to transport through the counterparty’s pipeline. Under this agreement, if the Company does not meet the volume commitment for transportation in a contract year, the Company will owe the fees to transport the committed volume whether or not the committed volume is utilized. The minimum contractual obligation at June 30, 2018 was approximately $45.8 million. The Company paid approximately $0.9 million and $1.5 million in transportation fees under this agreement during the three and six months ended June 30, 2018, respectively. In late 2017, the Company also entered into a fixed-fee NGL transportation and fractionation agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum contractual obligation during the seven-year period would be approximately $132.3 million. In April 2018, the Company entered into a short-term natural gas transportation agreement whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this short-term agreement, the Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation under this short-term contract at June 30, 2018 is approximately $4.6 million. This short-term agreement ends on September 30, 2019. The Company paid approximately $0.2 million in transportation fees under this agreement during the three and six months ended June 30, 2018. In addition, in April 2018, the Company entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation at June 30, 2018 was approximately $56.8 million. In May 2018, the Company also entered into a 10-year, fixed-fee natural gas sales agreement whereby the Company committed to deliver residue natural gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date of such pipeline, which is expected to be operational in late 2019. If the Company does not meet the volume commitment specified in the natural gas sales agreement, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at June 30, 2018 was approximately $200.6 million. Delaware Basin — San Mateo In February 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at June 30, 2018 was approximately $222.6 million. Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant. The expansion was completed late in the first quarter of 2018. San Mateo’s total commitments under these agreements are $55.3 million. The subsidiary of San Mateo paid approximately $1.1 million and $3.6 million under these agreements during the three and six months ended June 30, 2018. As of June 30, 2018, the remaining obligations under these agreements were $2.0 million, which are expected to be paid within the next few months. During the first quarter of 2018, a subsidiary of San Mateo entered into agreements for additional field compression and an amine gas treatment unit to maximize the operation of the Black River Processing Plant. San Mateo’s total commitments under these agreements are $19.9 million. The subsidiary of San Mateo paid approximately $6.0 million and $6.5 million under these agreements during the three and six months ended June 30, 2018. As of June 30, 2018, the remaining obligations under these agreements were $13.5 million, which are expected to be paid within the next year. Other Commitments The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. 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 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 $32.4 million at June 30, 2018. At June 30, 2018, 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 $47.2 million at June 30, 2018. 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.

Supplemental Disclosures

6 Months Ended

Jun. 30, 2018

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at June 30, 2018 and December 31, 2017 (in thousands).



	June 30, 2018		December 31, 2017
Accrued evaluated and unproved and unevaluated property costs	$	79,540	$	105,347
Accrued midstream property costs	11,459		14,823
Accrued cost to issue equity	73		—
Accrued lease operating expenses	14,209		12,611
Accrued interest on debt	8,345		8,345
Accrued asset retirement obligations	1,235		1,176
Accrued partners’ share of joint interest charges	14,824		27,628
Other	3,680		4,418
Total accrued liabilities	$	133,365	$	174,348

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2018 and 2017 (in thousands).



	Six Months Ended June 30,
	2018			2017
Cash paid for interest expense, net of amounts capitalized	$	14,286		$	15,875
Increase in asset retirement obligations related to mineral properties	$	834		$	1,978
Increase (decrease) in asset retirement obligations related to midstream properties	$	296		$	(138	)
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures	$	(26,389	)	$	43,797
(Decrease) increase in liabilities for midstream properties capital expenditures	$	(2,371	)	$	1,838
Stock-based compensation expense recognized as liability	$	(93	)	$	(339	)
Increase (decrease) in liabilities for accrued cost to issue equity	$	73		$	(343	)
Transfer of inventory from (to) oil and natural gas properties	$	343		$	(228	)
Transfer of inventory to midstream and other property and equipment	$	(2,390	)	$	—

The following table provides a reconciliation of cash and restricted cash recorded in the interim unaudited condensed consolidated balance sheets to cash and restricted cash as presented on the interim unaudited condensed consolidated statements of cash flows (in thousands).



	Six Months Ended June 30,
	2018		2017
Cash	$	122,450	$	131,467
Restricted cash	21,063		15,040
Total cash and restricted cash	$	143,513	$	146,507

Segment Information

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration, development and production of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, natural gas, oil and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo.

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



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Three Months Ended June 30, 2018
Oil and natural gas revenues	$	207,229		$	1,790	$	—		$	—		$	209,019
Midstream services revenues	—			19,896		—			(16,489		)	3,407
Realized loss on derivatives	(2,488		)	—		—			—			(2,488		)
Unrealized gain on derivatives	1,429			—		—			—			1,429
Expenses⁽¹⁾	126,025			9,363		18,475			(16,489		)	137,374
Operating income (loss)⁽²⁾	$	80,145		$	12,323	$	(18,475	)	$	—		$	73,993
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847
Capital expenditures⁽³⁾	$	199,345		$	32,900	$	732		$	—		$	232,977

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $64.5 million and $2.3 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $25,000.


(2)	Includes $5.8 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $16.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.



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

_____________________


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


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


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



	Exploration and Production								Consolidations and Eliminations			Consolidated Company
	Exploration and Production			Midstream		Corporate			Consolidations and Eliminations			Consolidated Company
Six Months Ended June 30, 2018
Oil and natural gas revenues	$	387,489		$	3,484	$	—		$	—		$	390,973
Midstream services revenues	—			35,708		—			(29,233		)	6,475
Realized loss on derivatives	(6,746		)	—		—			—			(6,746		)
Unrealized gain on derivatives	11,845			—		—			—			11,845
Expenses⁽¹⁾	232,180			16,561		35,684			(29,233		)	255,192
Operating income (loss)⁽²⁾	$	160,408		$	22,631	$	(35,684	)	$	—		$	147,355
Total assets	$	2,058,447		$	354,068	$	143,332		$	—		$	2,555,847
Capital expenditures⁽³⁾	$	388,790		$	78,617	$	1,258		$	—		$	468,665

_____________________


(1)	Includes depletion, depreciation and amortization expenses of $117.8 million and $3.9 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.6 million.


(2)	Includes $10.9 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.


(3)	Includes $38.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.



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

_____________________


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


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


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

Subsidiary Guarantors (Notes)

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

SUBSIDIARY GUARANTORS

Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At June 30, 2018, the Guarantor Subsidiaries were 100% owned by Matador. 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. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes.

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

Condensed Consolidating Balance Sheet
June 30, 2018

Matador

Non-Guarantor Subsidiaries

Guarantor Subsidiaries

Eliminating Entries

Consolidated

ASSETS

Intercompany receivable