Edgar Filing: Matador Resources Co

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

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

For the transition period from to

Commission file number 001-35410

MATADOR RESOURCES COMPANY

(Exact name of registrant as specified in its charter)


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

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

(972) 371-5200

(Registrant’s telephone number, including area code)

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

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

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

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

As of May 15, 2012, there were 55,507,543 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

MATADOR RESOURCES COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2012

INDEX


	Page

PART I — FINANCIAL INFORMATION		1

Item 1. — Financial Statements (Unaudited)		1

Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011		1

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011		2

Condensed Consolidated Statement of Shareholders’ Equity for the Three Months Ended March 31, 2012		3

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		4

Notes to Condensed Consolidated Financial Statements		5

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

Item 3. — Quantitative and Qualitative Disclosures About Market Risk		47

Item 4. — Controls and Procedures		49

PART II — OTHER INFORMATION		49

Item 1. — Legal Proceedings		49

Item 1A. — Risk Factors		50

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 3. — Defaults Upon Senior Securities		50

Item 4. — Mine Safety Disclosures		50

Item 5. — Other Information		50

Item 6. — Exhibits		50

SIGNATURES		53

Part I — Financial Information

Item 1. Financial Statements

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS — UNAUDITED


	March 31, 2012			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	2,373,853		$	10,284,180
Certificates of deposit		727,000			1,335,000
Accounts receivable
Oil and natural gas revenues		17,802,280			9,237,322
Joint interest billings		2,724,842			2,488,070
Other		1,099,885			1,446,113
Derivative instruments		10,908,380			8,988,767
Lease and well equipment inventory		1,343,416			1,343,416
Prepaid expenses		1,697,292			1,153,214

Total current assets		38,676,948			36,276,082
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated		489,385,342			423,944,476
Unproved and unevaluated		162,921,922			162,597,985
Other property and equipment		21,304,688			18,764,038
Less accumulated depletion, depreciation and amortization		(216,647,175	)		(205,441,724	)

Net property and equipment		456,964,777			399,864,775
Other assets
Derivative instruments		917,385			847,267
Deferred income taxes		—			1,593,331
Other assets		874,122			887,061

Total other assets		1,791,507			3,327,659

Total assets	$	497,433,232		$	439,468,516


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	5,868,441		$	18,841,295
Accrued liabilities		43,440,919			25,438,893
Royalties payable		3,196,701			1,855,296
Borrowings under Credit Agreement		—			25,000,000
Derivative instruments		3,089,211			171,252
Deferred income taxes		2,396,156			3,023,760
Dividends payable — Class B		—			68,713
Other current liabilities		53,697			176,868

Total current liabilities		58,045,125			74,576,077
Long-term liabilities
Borrowings under Credit Agreement		15,000,000			88,000,000
Asset retirement obligations		4,136,370			3,935,084
Derivative instruments		2,724,273			382,848
Deferred income taxes		2,098,105			—
Other long-term liabilities		1,333,242			1,059,314

Total long-term liabilities		25,291,990			93,377,246
Commitments and contingencies (Note 10)
Shareholders’ equity
Common stock — Class A, $0.01 par value, 80,000,000 shares authorized; 56,452,035 and 42,916,668 shares issued; and 55,272,860 and 41,737,493 shares outstanding, respectively		564,520			429,166
Common stock — Class B, $0.01 par value, zero and 2,000,000 shares authorized; zero and 1,030,700 shares issued and outstanding, respectively		—			10,307
Additional paid-in capital		402,244,834			263,561,890
Retained earnings		22,051,585			18,278,652
Treasury stock, at cost, 1,179,175 shares		(10,764,822	)		(10,764,822	)

Total shareholders’ equity		414,096,117			271,515,193

Total liabilities and shareholders’ equity	$	497,433,232		$	439,468,516

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

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended March 31,
	2012			2011
Revenues
Oil and natural gas revenues	$	29,163,667		$	13,698,578
Realized gain on derivatives		3,062,700			1,849,750
Unrealized loss on derivatives		(3,269,652	)		(1,668,115	)

Total revenues		28,956,715			13,880,213
Expenses
Production taxes and marketing		2,164,486			1,299,557
Lease operating		4,645,200			1,605,092
Depletion, depreciation and amortization		11,205,450			7,111,211
Accretion of asset retirement obligations		52,750			39,220
Full-cost ceiling impairment		—			35,673,098
General and administrative		3,789,424			2,618,591

Total expenses		21,857,310			48,346,769

Operating income (loss)		7,099,405			(34,466,556	)

Other income (expense)
Interest expense		(307,824	)		(106,465	)
Interest and other income		72,827			71,099

Total other expense		(234,997	)		(35,366	)

Income (loss) before income taxes		6,864,408			(34,501,922	)

Income tax provision (benefit)
Deferred		3,063,832			(6,906,257	)

Total income tax provision (benefit)		3,063,832			(6,906,257	)

Net income (loss)	$	3,800,576		$	(27,595,665	)

Earnings (loss) per common share
Basic
Class A	$	0.08		$	(0.65	)

Class B	$	0.15		$	(0.58	)

Diluted
Class A	$	0.08		$	(0.65	)

Class B	$	0.15		$	(0.58	)

Weighted average common shares outstanding
Basic
Class A		49,596,946			41,624,580
Class B		419,076			1,030,700

Total		50,016,022			42,655,280

Diluted
Class A		49,666,213			41,624,580
Class B		419,076			1,030,700

Total		50,085,289			42,655,280

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

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

For the three months ended March 31, 2012


	Common Stock										Additional
	Class A				Class B						paid-in			Retained			Treasury Stock
	Shares		Amount		Shares			Amount			capital			earnings			Shares			Amount			Total
Balance at January 1, 2012		42,916,668	$	429,166		1,030,700		$	10,307		$	263,561,890		$	18,278,652			(1,179,175	)	$	(10,764,822	)	$	271,515,193
Issuance of Class A common stock		12,209,167		122,092		—			—			146,387,912			—			—			—			146,510,004
Cost to issue equity		—		—		—			—			(11,262,499	)		—			—			—			(11,262,499	)
Conversion of Class B common stock to Class A common stock		1,030,700		10,307		(1,030,700	)		(10,307	)		—			—			—			—			—
Class A common stock issuable to Board members and advisors		—		—		—			—			11,020			—			—			—			11,020
Stock options expense		—		—		—			—			(5,524	)		—			—			—			(5,524	)
Stock options exercised		295,500		2,955		—			—			3,541,065			—			—			—			3,544,020
Restricted stock vested		—		—		—			—			10,970			—			—			—			10,970
Class B dividends declared		—		—		—			—			—			(27,643	)		—			—			(27,643	)
Current period net income		—		—		—			—			—			3,800,576			—			—			3,800,576

Balance at March 31, 2012		56,452,035	$	564,520		—		$	—		$	402,244,834		$	22,051,585			(1,179,175	)	$	(10,764,822	)	$	414,096,117

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

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Three Months Ended March 31,
	2012			2011
Operating activities
Net income (loss)	$	3,800,576		$	(27,595,665	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized loss on derivatives		3,269,652			1,668,115
Depletion, depreciation and amortization		11,205,450			7,111,211
Accretion of asset retirement obligations		52,750			39,220
Full-cost ceiling impairment		—			35,673,098
Stock option and grant expense		(373,372	)		42,342
Restricted stock expense		10,970			11,001
Deferred income tax provision (benefit)		3,063,832			(6,906,257	)
Changes in operating assets and liabilities
Accounts receivable		(8,455,502	)		(1,487,670	)
Prepaid expenses		(544,078	)		510,035
Other assets		12,939			—
Accounts payable, accrued liabilities and other current liabilities		(8,563,482	)		4,098,248
Royalties payable		1,341,405			416,170
Advances from joint interest owners		—			(722,843	)
Other long-term liabilities		288,706			(125,000	)

Net cash provided by operating activities		5,109,846			12,732,005
Investing activities
Oil and natural gas properties capital expenditures		(51,959,003	)		(34,113,878	)
Expenditures for other property and equipment		(1,413,013	)		(1,180,181	)
Purchases of certificates of deposit		(150,000	)		(1,329,000	)
Maturities of certificates of deposit		758,000			1,599,000

Net cash used in investing activities		(52,764,016	)		(35,024,059	)
Financing activities
Repayments of borrowings under Credit Agreement		(123,000,000	)		—
Borrowings under Credit Agreement		25,000,000			15,000,000
Proceeds from issuance of common stock		146,510,004			591,492
Cost to issue equity		(11,329,305	)		(31,877	)
Proceeds from stock options exercised		2,659,500			202,500
Payment of dividends — Class B		(96,356	)		(68,713	)

Net cash provided by financing activities		39,743,843			15,693,402

Decrease in cash and cash equivalents		(7,910,327	)		(6,598,652	)
Cash and cash equivalents at beginning of period		10,284,180			21,059,519

Cash and cash equivalents at end of period	$	2,373,853		$	14,460,867

Supplemental disclosures of cash flow information (Note 11)

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

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company (“Matador” or the “Company”) is an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Matador’s current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. In addition to these primary operating areas, Matador has acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where the Company continues to identify new oil and natural gas prospects.

On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011, the former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

MRC Energy Company holds the primary assets of the Company and has four wholly owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in southeast New Mexico. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations and also transports limited quantities of third-party natural gas.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of the Company’s consolidated financial position as of March 31, 2012, consolidated results of operations for the three months ended March 31, 2012 and 2011, consolidated shareholders’ equity for the three months ended March 31, 2012 and consolidated cash flows for the three months ended March 31, 2012 and 2011. Certain reclassifications have been made to prior period items to conform to the current period presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. Amounts as of December 31, 2011 are derived from the audited consolidated financial statements as filed with the SEC in our Annual Report on Form 10-K for the year ended December 31, 2011.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results for the interim periods shown in this report are not necessarily indicative of results to be expected for the full year due in part to volatility in oil and natural gas prices, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, oil and natural gas supply and demand, market competition and interruptions of production.

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 consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

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 exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $516,207 and $501,519 of its general and administrative costs for the three months ended March 31, 2012 and 2011, respectively. The Company capitalized $275,728 of its interest expense for the three months ended March 31, 2012. No interest expense was capitalized during the three months ended March 31, 2011.

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, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The need for a full-cost ceiling impairment is assessed on a quarterly basis. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas 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. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs for developing these reserves. 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 on the commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, 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.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

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 April 2011 through March 2012, these average oil and natural gas prices were $94.65 per Bbl and $3.731 per MMBtu (million British thermal units), respectively. For the period April 2010 through March 2011, these average oil and natural gas prices were $80.04 per Bbl and $4.102 per MMBtu. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were adjusted by property for energy content, transportation and marketing fees and regional price differentials. At March 31, 2012 and 2011, the Company’s oil and natural gas reserves estimates 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.

Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at March 31, 2012, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs for the three months ended March 31, 2012. Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at March 31, 2011, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $22,989,866. The Company recorded an impairment charge of $35,673,098 to its net capitalized costs and a deferred income tax credit of $12,683,232 related to the full-cost ceiling limitation at March 31, 2011. Corresponding charges were also recorded to the Company’s unaudited condensed consolidated statement of operations for the three months ended March 31, 2011.

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 balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

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. Dry holes are included in the amortization base immediately upon determination that the well is not productive.

Earnings Per Common Share

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

Prior to the consummation of the Company’s Initial Public Offering (see Note 7) in February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during the three months ended March 31, 2012 and 2011 totaled $27,643 and $68,713, respectively. Class B dividends declared during the fourth quarter of 2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356. As of March 31, 2012, the Company had not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the common stock.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and undistributed earnings (loss) per common share as reported for the three months ended March 31, 2012 and 2011.


	Three Months Ended March 31,
	2012			2011
Net income (loss) — numerator
Net income (loss)	$	3,800,576		$	(27,595,665	)
Less dividends to Class B shareholders — Distributed earnings		(27,643	)		(68,713	)

Undistributed earnings (loss)	$	3,772,933		$	(27,664,378	)

Weighted average common shares outstanding — denominator
Basic
Class A		49,596,946			41,624,580
Class B		419,076			1,030,700

Total		50,016,022			42,655,280

Diluted
Class A
Weighted average common shares outstanding for basic earnings (loss) per share		49,596,946			41,624,580
Dilutive effect of options		69,267			—

Class A weighted average common shares outstanding – diluted		49,666,213			41,624,580
Class B
Weighted average common shares outstanding – no associated dilutive shares		419,076			1,030,700

Total diluted weighted average common shares outstanding		50,085,289			42,655,280

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued


	Three Months Ended March 31,
	2012		2011
Earnings (loss) per common share
Basic
Class A
Distributed earnings	$	—	$	—
Undistributed earnings (loss)	$	0.08	$	(0.65	)

Total	$	0.08	$	(0.65	)

Class B
Distributed earnings	$	0.07	$	0.07
Undistributed earnings (loss)	$	0.08	$	(0.65	)

Total	$	0.15	$	(0.58	)

Diluted
Class A
Distributed earnings	$	—	$	—
Undistributed earnings (loss)	$	0.08	$	(0.65	)

Total	$	0.08	$	(0.65	)

Class B
Distributed earnings	$	0.07	$	0.07
Undistributed earnings (loss)	$	0.08	$	(0.65	)

Total	$	0.15	$	(0.58	)

A total of 1,178,500 options to purchase shares of the Company’s Class A common stock were excluded from the calculations above for the three months ended March 31, 2011 because their effects were anti-dilutive.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

Fair Value Measurements

The Company measures and reports certain 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). The Company follows Financial Accounting Standards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value.

Recent Accounting Pronouncements

Balance Sheet. In December 2011, the FASB issued Accounting Standards Update, or ASU, 2011-11, Balance Sheet. The requirements amend the disclosure requirements related to offsetting in Accounting Standards Codification, or ASC, 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The adoption of ASU 2011-11 is not expected to have a material effect on the Company’s consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for annual reporting periods beginning on or after January 1, 2013 and are to be applied retrospectively for all periods presented.

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 amends ASC 820 Fair Value Measurements, providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company adopted ASU 2011-04 on January 1, 2012; adoption did not have a material effect on the Company’s consolidated financial statements, but did require additional disclosures (see Note 9).

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the three months ended March 31, 2012.


Beginning asset retirement obligations	$	4,269,584
Liabilities incurred during period		152,953
Liabilities settled during period		—
Accretion expense		52,750

Ending asset retirement obligations	$	4,475,287

At March 31, 2012, $338,917 of the Company’s asset retirement obligations were classified as current liabilities and included in “accrued liabilities” in the Company’s unaudited condensed consolidated balance sheet.

NOTE 4 — REVOLVING CREDIT AGREEMENT

In December 2011, the Company amended and restated its senior secured revolving credit agreement (“Credit Agreement”) for which Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount from $150,000,000 to $400,000,000. Borrowings under the Credit Agreement are limited to the lesser of $400,000,000 or the borrowing base. At March 31, 2012, the borrowing base was $125,000,000. The Credit Agreement matures in December 2016.

MRC Energy Company is the borrower under the Credit Agreement and borrowings are secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with Comerica Bank (or an affiliate thereof) are also secured by the collateral and guaranteed by the subsidiaries of MRC Energy Company.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 4 — REVOLVING CREDIT AGREEMENT – Continued

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, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which the Company has no control. At December 31, 2011, the borrowing base was $125,000,000 and we had $113,000,000 in outstanding borrowings under the Credit Agreement. In January 2012, the Company borrowed an additional $10,000,000 to finance a portion of its working capital requirements and capital expenditures, bringing the then outstanding revolving borrowings under the Credit Agreement to $123,000,000. Following the completion of the Initial Public Offering in February 2012, the Company used a portion of the net proceeds to repay the then outstanding $123,000,000 under the Credit Agreement in full, at which time the borrowing base was reduced to $100,000,000. On February 28, 2012, the borrowing base was increased to $125,000,000 pursuant to a special borrowing base redetermination made at the Company’s request. The borrowing base increase was determined by the lenders based upon, among other items, the increase in the Company’s proved oil and natural gas reserves at December 31, 2011.

In March 2012, the Company borrowed $15,000,000 under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures. At March 31, 2012, the Company had $15,000,000 in borrowings outstanding under the Credit Agreement, approximately $1,300,000 in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $108,700,000 available for additional borrowings. At March 31, 2012, the Company’s outstanding borrowings bore interest at approximately 2.0% per annum.

Both the Company and the lenders may each request an unscheduled redetermination of the borrowing base twice at any time during the first year of the Credit Agreement and once between scheduled redetermination dates thereafter. We requested one such unscheduled redetermination in February 2012. 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 will be determined based on market conditions at the time of the borrowing base increase. If 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.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 4 — REVOLVING CREDIT AGREEMENT – Continued

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 weighted average of rates used in overnight federal funds transactions with members of the Federal Reserve System plus 1.0% or (ii) the prime rate for Comerica Bank then in effect or (iii) a daily adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on the level of borrowings under the 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 interest rate appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Comerica Bank 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 1.375% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A facility fee of 0.375% to 0.50%, depending on the amounts borrowed, is also paid quarterly in arrears. The Company includes this facility fee in its interest rate calculations and related disclosures.

Key financial covenants under the Credit Agreement require us to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning March 31, 2012, and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less.

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

•

incur indebtedness or grant liens on any of its 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; and

•

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

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 4 — REVOLVING CREDIT AGREEMENT – Continued

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 notes or any reimbursement obligation under any letter of credit when due or any fees or other amount 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.

At March 31, 2012, the Company believes that it was in compliance with the terms of the Credit Agreement. We obtained a written extension until May 1, 2012 to comply with a covenant under the Credit Agreement requiring the submission of certain year-end 2011 operating information on or before March 1, 2012. We subsequently furnished this information to the lenders prior to May 1, 2012.

NOTE 5 — INCOME TAXES

The Company had an effective income tax rate of 44.6% for the three months ended March 31, 2012. Total income tax expense for the three months ended March 31, 2012 differed from amounts computed by applying the U.S. statutory tax rates to income taxes due primarily to state taxes and the impact of an adjustment to the estimated permanent differences between book and taxable income related to stock compensation expense in prior periods. The Company had a net loss for the three months ended March 31, 2011.

The adjustment noted above resulted in a charge to deferred tax assets and additional deferred income taxes of $721,005. Although the amount may be considered material to the financial results for the three months ended March 31, 2012, management does not believe that recording the adjustment in the current period will have a material effect on the financial results for the year ended December 31, 2012.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 6 — STOCK-BASED COMPENSATION

Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan provides for a maximum of 4,000,000 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 and other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, contractors and outside directors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors of the Company.

During the three months ended March 31, 2012, the Company granted one of its executive officers the option to purchase 150,000 shares of its common stock at $12.00 per share. The award was classified as an equity award and the total grant date fair value of the option was approximately $1,054,000 which will be expensed over a service period of approximately three years. The Company recognized approximately $70,000 in stock-based compensation expense related to this grant during the three months ended March 31, 2012.

NOTE 7 — COMMON STOCK

On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the initial public offering of its common stock (the “Initial Public Offering”). The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC; Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc.; and Comerica Securities, Inc. On February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share.

Pursuant to its Prospectus dated February 1, 2012, the Company and the selling shareholders offered 13,333,334 shares of the Company’s common stock for sale. The Company offered 11,666,667 shares of its common stock, and the selling shareholders offered 1,666,667 shares. On February 7, 2012, the Company closed the Initial Public Offering and issued 11,666,667 shares of its common stock pursuant to the Initial Public Offering.

The Company and the selling shareholders granted the underwriters the right to purchase up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following the Initial Public Offering to cover over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000 shares. On March 2, 2012, the underwriters exercised their option to purchase an additional 1,550,000 shares, including the purchase of 542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012, the Company closed this transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise of the over-allotment.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 7 — COMMON STOCK – Continued

Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of 12,209,167 shares of its common stock at $12.00 per share. The Company received cash proceeds of approximately $136,600,000 from this transaction, net of underwriting discounts and commissions. The Company did not receive any proceeds from the sale of shares of its common stock by the selling shareholders. The underwriters received underwriting discounts and commissions totaling approximately $9,900,000, and the Company incurred additional costs of approximately $3,500,000 in connection with the offering, which amounted to total fees and costs of approximately $13,400,000, of which approximately $2,100,000 was incurred in a prior period. On February 8, 2012, the Company used a portion of the net proceeds of the offering to repay the $123,000,000 in borrowings then outstanding under its Credit Agreement in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures.

Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net proceeds of $2,659,500. The Class A common stock is now referred to as the common stock.

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil and natural gas prices. These instruments consist of put and call options in the form of costless collars. The Company records derivative financial instruments on its balance sheet 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. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly traded securities. The Company has evaluated the credit standing of its single counterparty, Comerica Bank, in determining the fair value of these derivative financial instruments.

The Company has entered into various costless collar contracts to mitigate its exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions 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. When the settlement price is below the price floor established by these collars, the Company receives from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by these collars, the Company pays to Comerica, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS – Continued

The Company has entered into various costless collar transactions for natural gas, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions 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 last day of that contract period. When the settlement price is below the price floor established by these collars, the Company receives from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by these collars, the Company pays to Comerica, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume.

At March 31, 2012, the Company had multiple 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 2012, 2013 and 2014.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at March 31, 2012.


Commodity	Calculation Period	Notional Quantity (Bbl/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)		Fair Value of Asset (Liability)
Oil	04/01/2012 – 12/31/2012		20,000		90.00		104.20	$	(854,699	)
Oil	04/01/2012 – 12/31/2012		10,000		90.00		108.00		(255,085	)
Oil	04/01/2012 – 12/31/2012		10,000		90.00		109.50		(205,318	)
Oil	04/01/2012 – 06/30/2012		20,000		90.00		113.75		(18,545	)
Oil	04/01/2012 – 12/31/2012		20,000		90.00		111.00		(320,596	)
Oil	04/01/2012 – 03/31/2013		20,000		90.00		110.00		(542,988	)
Oil	07/01/2012 – 12/31/2012		20,000		90.00		111.90		(237,974	)
Oil	07/01/2012 – 12/31/2012		20,000		95.00		116.00		62,891
Oil	01/01/2013 – 12/31/2013		20,000		85.00		102.25		(1,735,790	)
Oil	01/01/2013 – 12/31/2013		20,000		90.00		115.00		(82,408	)
Oil	01/01/2013 – 12/31/2013		20,000		85.00		110.40		(816,436	)
Oil	01/01/2013 – 12/31/2013		20,000		85.00		108.80		(904,064	)
Oil	01/01/2013 – 06/30/2014		8,000		90.00		114.00		(2,101	)
Oil	01/01/2013 – 06/30/2014		12,000		90.00		115.50		99,629

Total Oil									(5,813,484	)

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS – Continued


Commodity	Calculation Period	Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)		Fair Value of Asset (Liability)
Natural Gas	04/01/2012 – 12/31/2012		300,000		4.50		5.60		5,430,640
Natural Gas	04/01/2012 – 07/31/2013		150,000		4.50		5.75		4,005,490
Natural Gas	04/01/2012 – 12/31/2012		150,000		4.25		6.17		2,389,635

Total Natural Gas									11,825,765

Total open costless collar contracts								$	6,012,281

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

	$(0,000,000		$(0,000,000			$(0,000,000
Type of Instrument	Location in Balance Sheet	March 31, 2012			December 31, 2011
Derivative Instrument
Oil	Current liabilities: Derivative instruments	$	(3,089,211	)	$	(171,252	)
Oil	Long-term liabilities: Derivative instruments		(2,724,273	)		(382,848	)
Natural Gas	Current assets: Derivative instruments		10,908,380			8,988,767
Natural Gas	Other assets: Derivative instruments		917,385			847,267

Total		$	6,012,281		$	9,281,934

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. These derivative financial instruments are not designated as hedging instruments.

	$(0,000,000		$(0,000,000			$(0,000,000
		Three Months Ended March 31,
Type of Instrument	Location in Statement of Operations	2012			2011
Derivative Instrument
Natural Gas	Revenues: Realized gain on derivatives	$	3,062,700		$	1,849,750

Realized gain on derivatives			3,062,700			1,849,750
Oil	Revenues: Unrealized loss on derivatives		(5,259,384	)		—
Natural Gas	Revenues: Unrealized gain (loss) on derivatives		1,989,732			(1,668,115	)

Unrealized loss on derivatives			(3,269,652	)		(1,668,115	)

Total		$	(206,952	)	$	181,635

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 9 — FAIR VALUE MEASUREMENTS

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

Level 1

Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

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 using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, 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. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources.

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 March 31, 2012 and December 31, 2011, the carrying values reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable and other current liabilities approximate their fair values due to their short-term maturities and are classified at Level 1.

At March 31, 2012 and December 31, 2011, the carrying value of borrowings under the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 9 — FAIR VALUE MEASUREMENTS — Continued

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of March 31, 2012 and December 31, 2011.


Description	Fair Value Measurements at March 31, 2012 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	—	$	727,000		$	—	$	727,000
Oil and natural gas derivatives		—		11,825,765			—		11,825,765
Oil and natural gas derivatives		—		(5,813,484	)		—		(5,813,484	)

Total	$	—	$	6,739,281		$	—	$	6,739,281


Description	Fair Value Measurements at December 31, 2011 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	—	$	1,335,000		$	—	$	1,335,000
Oil and natural gas derivatives		—		9,836,034			—		9,836,034
Oil and natural gas derivatives		—		(554,100	)		—		(554,100	)

Total	$	—	$	10,616,934		$	—	$	10,616,934

Additional disclosures related to derivative financial instruments are provided in Note 8. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative financial instruments (e.g., oil and natural gas derivatives) should be classified at Level 2.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 9 — FAIR VALUE MEASUREMENTS — Continued

The Company accounts for additions to asset retirement obligations and lease and well equipment inventory at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis for the periods ended March 31, 2012 and December 31, 2011.


Description	Fair Value Measurements for the period ended March 31, 2012 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	—	$	—	$	(152,953	)	$	(152,953	)

Total	$	—	$	—	$	(152,953	)	$	(152,953	)


Description	Fair Value Measurements for the period ended December 31, 2011 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	—	$	—	$	(186,873	)	$	(186,873	)
Lease and well equipment inventory		—		—		1,343,416			1,343,416

Total	$	—	$	—	$	1,156,543		$	1,156,543

For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be classified at Level 3 when adjusted for impairment. The Company recorded additions to asset retirement obligations of $152,953 for the three months ended March 31, 2012 and $186,873 for the year ended December 31, 2011, respectively.

For purposes of fair value measurement, the Company determined that lease and well equipment inventory should be classified as Level 3. In 2011, the Company recorded an impairment to some of its equipment held in inventory consisting primarily of drilling rig parts of $17,500 and pipe and other equipment of $22,276; no impairment to any equipment was recorded for the three months ended March 31, 2012. The Company periodically obtains estimates of the market value of its equipment held in inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 10 — COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located in 28,743 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2011, the Company agreed to a restated third amendment to its office lease agreement, in which the office space was increased to 28,743 square feet and the term of the lease was extended from July 1, 2011 to June 30, 2022. The effective base rent over the term of the new lease extension is $19.75 per square foot per year. The base rate escalates several times during the course of the lease, specifically in July 2015, July 2017, July 2019 and July 2020.

Other Commitments

During the first quarter of 2012, the Company extended one of its drilling rig contracts in south Texas for an additional nine months. The Company terminated its second contract with no termination penalty and entered into a new contract for a higher performance rig with the same drilling rig contractor for a period of one year. Drilling operations under these two contracts began in early March 2012. Should the Company elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rate being charged to the Company prior to the end of their respective terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under these contracts were approximately $9,800,000 at March 31, 2012.

At March 31, 2012, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells in the Haynesville and Eagle Ford shales. The Company’s working interests in these wells are small, and most of these wells were in progress at March 31, 2012. If all of these wells are drilled and completed, the Company’s minimum outstanding aggregate commitments at March 31, 2012 for its participation in these non-operated Haynesville wells were approximately $5,200,000, and the Company expects these costs to be incurred in the next 12 months.

In June 2011, the Company awarded bonuses to certain of its current employees, but not including any of its executive officers, in the aggregate amount of $1,240,000. These bonuses will be payable in a lump sum to each of these employees in June 2014, provided each remains an employee in good standing with the Company at that time.

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 10 — COMMITMENTS AND CONTINGENCIES – Continued

Legal Proceedings

The Company is a defendant in several lawsuits encountered in the ordinary course of its business, none of which, in the opinion of management, will have a material adverse impact on the Company’s financial position, results of operations or cash flows.

NOTE 11 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at March 31, 2012 and December 31, 2011.


	March 31, 2012		December 31, 2011
Accrued evaluated and unproved and unevaluated property costs	$	34,974,906	$	18,184,818
Accrued support equipment and facilities costs		1,315,000		215,517
Accrued cost to issue equity		265,014		331,818
Accrued stock-based compensation		1,450,213		2,859,527
Accrued lease operating expenses		3,156,761		575,318
Accrued interest on borrowings under Credit Agreement		84,712		—
Accrued asset retirement obligations		338,917		334,500
Other		1,855,396		2,937,395

Total accrued liabilities	$	43,440,919	$	25,438,893

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 11 — SUPPLEMENTAL DISCLOSURES – Continued

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the three months ended March 31, 2012 and 2011.


	Three Months Ended March 31,
	2012			2011
Cash paid for interest expense, net of amounts capitalized	$	479,521		$	98,266
Asset retirement obligations related to mineral properties		124,799			58,265
Asset retirement obligations related to support equipment and facilities		28,154			16,818
Increase in liabilities for oil and natural gas properties capital expenditures		13,681,100			4,829,298
Increase (decrease) in liabilities for support equipment and facilities		1,099,483			(40,145	)
(Decrease) increase in liabilities for accrued cost to issue equity		(66,806	)		235,535
Stock-based compensation expense recognized as liability		(454,687	)		(16,250	)
Transfer of inventory from oil and natural gas properties		—			(156,706	)
Receivable for inventory from other joint interest owners		—			(156,706	)

Matador Resources Company and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED) – CONTINUED

NOTE 12 — SUBSEQUENT EVENTS

On April 16, 2012, the Board of Directors approved an award of stock options, restricted stock and restricted stock units to both executive and non-executive employees under the 2012 Incentive Plan. Non-qualified options to purchase an aggregate of 472,318 shares of the Company’s common stock at $10.49 per share were awarded; these options vest over four years. A total of 116,842 shares of time-lapse restricted stock was granted, and these shares also vest over four years. A total of 116,841 shares of performance-based restricted stock was granted. These shares vest based on the outcome of the Company’s total shareholder return over a three-year period as compared to a designated peer group. This award may result in the issuance of up to 116,841 restricted stock units in addition to the restricted stock grants. This award may also result in no performance-based restricted shares or restricted share units being issued pursuant to the grant.

In April 2012, the Company borrowed an additional $15,000,000 under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At May 15, 2012, the Company had $30,000,000 in borrowings outstanding under the Credit Agreement and approximately $1,300,000 in letters of credit issued pursuant to the Credit Agreement. The outstanding borrowings bore interest at approximately 2.0% per annum.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

In this Quarterly Report on Form 10-Q, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our Initial Public Offering on February 7, 2012, as the Class A common stock became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our Initial Public Offering.

For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural Gas Terms” included with our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q constitute “forward-looking statements” within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:

•

our business strategy;

•

our reserves and the present value thereof;

•

our technology;

•

our cash flows and liquidity;

•

our financial strategy, budget, projections and operating results;

•

our oil and natural gas realized prices;

•

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

•

the availability of drilling and production equipment;

•

the availability of oil field labor;

•

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

•

the availability and terms of capital;

•

our drilling of wells;

•

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

•

our marketing of oil and natural gas;

•

our exploitation projects or property acquisitions;

•

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

•

general economic conditions;

•

competition in the oil and natural gas industry;

•

the effectiveness of our risk management and hedging activities;

•

environmental liabilities;

•

counterparty credit risk;

•

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

•

our future operating results;

•

our estimated future reserves and the present value thereof;

•

our plans, objectives, expectations and intentions contained in this report that are not historical; and

•

other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

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

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

Overview

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resources plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas of Utah and Idaho where we continue to identify new oil and gas prospects.

During the first quarter of 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in south Texas. We also participated in several non-operated Haynesville shale wells in northwest Louisiana where we owned small working interests. During the three months ended March 31, 2012, we completed and began producing oil and/or natural gas from 6 gross/5.9 net operated Eagle Ford shale wells and 12 gross/0.6 net non-operated Haynesville shale wells. We had two contracted drilling rigs operating in south Texas throughout the first quarter of 2012, and all of our operated drilling and completion activities were focused on the Eagle Ford shale. At May 15, 2012, we continue to have two contracted drilling rigs operating in south Texas: one drilling our first Eagle Ford well in Zavala County and one in Karnes County.

Our average daily production for the three months ended March 31, 2012 was approximately 48.1 MMcfe per day, including approximately 2,200 Bbl of oil per day and 34.9 MMcf of natural gas per day, as compared to approximately 37.8 MMcfe per day, including approximately 210 Bbl of oil per day and 36.5 MMcfe per day for the three months ended March 31, 2011. Oil production comprised approximately 27% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) during the first quarter of 2012 as compared to approximately 3% of our total production during the first quarter of 2011.

At March 31, 2012, based on the reserves audit by our independent reservoir engineers, Netherland, Sewell & Associates, Inc., we had 203.1 Bcfe of estimated proved reserves with a PV-10 of $329.6 million and a Standardized Measure of $287.4 million. At March 31, 2012, 36% of our estimated proved reserves were proved developed reserves, 17% of our estimated proved reserves were oil and 83% of our estimated proved reserves were natural gas. At March 31, 2011, based on the reserves audit by our independent reservoir engineers, we had 154.8 Bcfe of estimated proved reserves with a PV-10 of $140.6 million and a Standardized Measure of $131.5 million. At March 31, 2011, 36% of our estimated proved reserves were proved developed reserves, 3% of our estimated proved reserves were oil and 97% of our estimated proved reserves were natural gas.

During 2012, we intend to allocate 84% of our 2012 capital expenditure budget of $313.0 million to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploratory projects like the Meade Peak shale in southwest Wyoming, until natural gas prices improved significantly from their recent levels. In addition, as a result of these low natural gas prices, several of our non-operated Haynesville shale wells were shut in for brief periods or produced less natural gas than we anticipated during the first quarter of 2012 as the operators curtailed a portion of the natural gas production from these wells.

As we transition our operations to the Eagle Ford shale play in south Texas, we may face challenges associated with establishing operations and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to transport, process and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure and facilities on our leases throughout the area. We believe we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and particularly hydraulic fracturing services, for any wells drilled during the first quarter of 2012, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable drilling and completion services and reducing drilling and completion costs will be essential to the successful development of the Eagle Ford shale play.

We experienced temporary pipeline interruptions from time to time during the three months ended March 31, 2012 associated with natural gas production from our Eagle Ford shale wells and have elected to either shut in wells for brief periods or to flare some of the natural gas we produced. We believe that these pipeline interruptions and capacity constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

On February 2, 2012, our common stock began trading on the New York Stock Exchange, or NYSE, under the symbol “MTDR.” Our general and administrative expenses have increased as a result of us operating as a public company. These increased expenses include costs associated with, among other items, legal and accounting support services, filing annual and quarterly reports with the SEC, investor relations activities, directors’ fees, incremental directors’ and officers’ liability insurance costs, transfer and registrar agent fees and expenses associated with compliance with the Sarbanes-Oxley Act and other regulations. In addition, we have increased our staff size and compensation and incurred other ongoing general and administrative expenses necessary to maintain and grow

a publicly traded exploration and production company. As a result, we believe that our general and administrative expenses for future periods may continue to increase. Our consolidated financial statements for future periods will reflect these increased expenses and affect the comparability of our financial statements with periods before the completion of our Initial Public Offering.

Initial Public Offering

We closed the Initial Public Offering of our common stock on February 7, 2012 and closed the over-allotment option on March 7, 2012. We issued 12,209,167 shares of common stock and 2,674,167 shares of common stock were sold by the selling shareholders. The shares were sold at a price to the public of $12.00 per share and we received cash proceeds of approximately $136.6 million from this transaction, net of underwriting discounts and commissions. We did not receive any proceeds from the sale of shares by the selling shareholders. The underwriters received underwriting discounts and commissions totaling approximately $9.9 million, and we incurred additional costs of approximately $3.5 million in connection with the offering, which amounted to total fees and costs of approximately $13.4 million. We used $123.0 million of the net proceeds to repay the then outstanding borrowings under our Credit Agreement. We used the remaining net proceeds to fund a portion of our 2012 capital expenditure requirements.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at March 31, 2012 and March 31, 2011. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.


	At March 31,⁽¹⁾
	2012			2011
Estimated Proved Reserves Data:⁽²⁾
Estimated proved reserves:
Oil (MBbl)		5,738			780
Natural Gas (Bcf)		168.7			150.1

Total (Bcfe)		203.1			154.8

Estimated proved developed reserves:
Oil (MBbl)		2,678			403
Natural Gas (Bcf)		56.1			53.7

Total (Bcfe)		72.1			56.1

Percent developed		35.5	%		36.2	%
Estimated proved undeveloped reserves:
Oil (MBbl)		3,060			377
Natural Gas (Bcf)		112.6			96.5

Total (Bcfe)		131.0			98.7

PV-10⁽³⁾ (in millions)	$	329.6		$	140.6
Standardized Measure⁽⁴⁾ (in millions)	$	287.4		$	131.5

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

(2)

Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from April 2011 to March 2012 were $94.65 per Bbl for oil and $3.731 per MMBtu for natural gas and for the period from April 2010 to March 2011 were $80.04 per Bbl for oil and $4.102 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.

(3)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at March 31, 2012 and 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at March 31, 2012 and 2011 were, in millions, $42.2 and $9.1, respectively.

(4)

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

Our total proved oil and natural gas reserves increased from 154.8 Bcfe at March 31, 2011 to 203.1 Bcfe at March 31, 2012. This increase is attributable to proved reserves added due to our drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in total proved oil reserves specifically from 780 MBbl at March 31, 2011 to 5,738 MBbl at March 31, 2012 is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our total proved reserves at March 31, 2012 were approximately 36% proved developed reserves and were made up of approximately 17% oil and 83% natural gas. Our total proved reserves at March 31, 2011 were approximately 36% proved developed reserves and were made up of approximately 3% oil and 97% natural gas.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. Although this decline in natural gas prices has not yet impacted the classification of our natural gas reserves at March 31, 2012, if natural gas prices continue to remain at or near these levels or if natural gas prices decline further, the unweighted arithmetic average of the first-day-of-the month prices for the previous 12 months used to estimate natural gas reserves will also continue to decline in future periods. Should this occur, the unweighted arithmetic average natural gas price for the previous 12 months, as adjusted by property for energy content, marketing and transportation fees and regional price differentials, may decline to a level where we are no longer able to classify a significant portion of our proved undeveloped natural gas reserves, particularly those associated with the Haynesville shale in northwest Louisiana, as proved undeveloped reserves. Should these natural gas volumes no longer be classified as proved undeveloped reserves, the net capitalized costs of our oil and natural gas properties less related deferred income taxes may exceed the present value of after-tax future net cash flows from our proved oil and natural gas reserves, discounted at 10%, in future periods, and if so, such excess must then be charged to operations as a full-cost ceiling impairment. As a non-cash item, a full-cost ceiling impairment impacts the accumulated depletion and net carrying value of our assets on the balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on our cash flows from operations.

There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Critical Accounting Policies

There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Recent Accounting Pronouncements

There have been no additional recent accounting pronouncements impacting our financial reporting from those set forth in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Results of Operations

Revenues

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


	Three Months Ended March 31,
	2012			2011
	(Unaudited)			(Unaudited)
Operating Data:
Revenues (in thousands):
Oil	$	21,547		$	1,680
Natural gas		7,617			12,019

Total oil and natural gas revenues		29,164			13,699
Realized gain on derivatives		3,063			1,849
Unrealized loss on derivatives		(3,270	)		(1,668	)

Total revenues	$	28,957		$	13,880

Net Production Volumes:
Oil (MBbl)		200			19
Natural gas (Bcf)		3.2			3.3
Total natural gas equivalents (Bcfe)⁽¹⁾		4.4			3.4
Average net daily production (MMcfe/d)⁽¹⁾		48.1			37.8
Average Sales Prices:
Oil (per Bbl)	$	107.57		$	89.11
Natural gas, with realized derivatives (per Mcf)	$	3.36		$	4.22
Natural gas, without realized derivatives (per Mcf)	$	2.40		$	3.65

(1)	Estimated using a conversion ratio of one Bbl per six Mcf.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Oil and natural gas revenues. Our oil and natural gas revenues increased by approximately $15.5 million to approximately $29.2 million, or an increase of about 113% for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. This increase in oil and natural gas revenues reflects an increase in our oil revenues of $19.9 million and a decrease in our natural gas revenues of $4.4 million for the three months ended March 31, 2012 as compared to the comparable period in 2011. Our oil revenues increased almost 13-fold to $21.5 million for the three months ended March 31, 2012 as compared to $1.7 million for the three months ended March 31, 2011. Our oil production increased just over 10-fold to approximately 200,000 Bbl of oil, or about 2,200 Bbl of oil per day, from approximately 19,000 Bbl of oil, or about 210 Bbl of oil per day, due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher average oil price of $107.57 per Bbl realized during the first quarter of 2012 as compared to an average oil price of $89.11 per Bbl realized during the first quarter of 2011. The decrease in our natural gas revenues reflects a decline in our natural gas production by about 3% to approximately 3.2 Bcf for the three months ended March 31, 2012 as compared to approximately 3.3 Bcf for the three months ended March 31, 2011. This decline in natural gas production is due to several factors, including (i) our decision not to drill any operated Haynesville shale wells in 2012, (ii) the partial curtailment of natural gas production from some of our non-operated Haynesville shale wells in north Louisiana and (iii) the flaring of a portion of the natural gas produced from our newly completed Eagle Ford shale wells in south Texas as a result of gas pipeline constraints and awaiting the completion of production facilities. This decrease in natural gas revenues also results from a significantly lower average natural gas price of $2.40 per Mcf realized during the first quarter of 2012 as compared to an average natural gas price of $3.65 per Mcf realized during the first quarter of 2011.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately $1.2 million to $3.1 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. For the three months ended March 31, 2012, all of this realized gain was attributable to our natural gas derivative contracts. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the comparable periods. We realized approximately $1.70 per MMBtu hedged on all of our open natural gas costless collar contracts during the three months ended March 31, 2012 as compared to $1.31 per MMBtu hedged on all of our open natural gas costless collar contracts during the three months ended March 31, 2011. Our total natural gas volumes hedged for the three months ended March 31, 2012 were also approximately 28% higher than the total natural gas volumes hedged for the same period in 2011.

Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $3.3 million for the three months ended March 31, 2012 as compared to an unrealized loss of $1.7 million for the three months ended March 31, 2011. During the period from December 31, 2011 to March 31, 2012, the net fair value of our open oil and natural gas costless collar contracts decreased from approximately $9.3 million to approximately $6.0 million, resulting in an unrealized loss on derivatives of approximately $3.3 million for the three months ended March 31, 2012. This decrease in the net fair value of our open oil and natural gas costless collar contracts for the three months ended March 31, 2012 was due primarily to an increase in oil prices that reduced the fair value of our open oil contracts, partially offset by a decrease in natural gas prices that increased the fair value of our open natural gas contracts. During the first quarter of 2012, we also entered into additional oil costless collar contracts. During the period from December 31, 2010 to March 31, 2011, the net fair value of our open natural gas costless collar contracts decreased from $4.1 million to $2.4 million, resulting in an unrealized loss of derivatives of $1.7 million for the three months ended March 31, 2011. We had no open oil costless collar contracts during the three months ended March 31, 2011.

Expenses

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


	Three Months Ended
	March 31,
	2012			2011
(In thousands, except expenses per Mcfe)	(Unaudited)			(Unaudited)
Expenses:
Production taxes and marketing	$	2,165		$	1,300
Lease operating		4,645			1,605
Depletion, depreciation and amortization		11,205			7,111
Accretion of asset retirement obligations		53			39
Full-cost ceiling impairment		—			35,673
General and administrative		3,789			2,619

Total expenses		21,857			48,347
Operating income (loss)		7,100			(34,467	)
Other income (expense):
Interest expense		(308	)		(106	)
Interest and other income		73			71

Total other expense		(235	)		(35	)
Income (loss) before income taxes		6,865			(34,502	)
Total income tax provision (benefit)		3,064			(6,906	)
Net income (loss)	$	3,801		$	(27,596	)
Expenses per Mcfe:
Production taxes and marketing	$	0.49		$	0.38
Lease operating	$	1.06		$	0.47
Depletion, depreciation and amortization	$	2.56		$	2.09
General and administrative	$	0.87		$	0.77

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Production taxes and marketing. Our production taxes and marketing expenses increased by approximately $0.9 million to approximately $2.2 million, or an increase of approximately 67% for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The increase in our production taxes and marketing expenses reflects the increases in both our total oil and natural gas production and revenues by 29% and 113%, respectively, during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The majority of this increase was attributable to production taxes and marketing expenses associated with the large increase in oil production resulting from our drilling operations in the Eagle Ford shale in south Texas. Our total production was comprised of approximately 27% oil and 73% natural gas for the three months ended March 31, 2012 as compared to approximately 3% oil and 97% natural gas during the same period in 2011. On a unit-of-production basis, our production taxes and marketing expenses increased by 29% to $0.49 per Mcfe for the three months ended March 31, 2012 as compared to $0.38 per Mcfe for the three months ended March 31, 2011.

Lease operating expenses. Our lease operating expenses increased by approximately $3.0 million to approximately $4.6 million, or an increase of almost three-fold for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. During these respective periods, our total oil and natural gas production increased 29% from 3.4 Bcfe to 4.4 Bcfe, including an almost 10-fold increase in oil production from approximately 19,000 Bbl to approximately 200,000 Bbl. Our lease operating expenses per unit of production increased 126% to $1.06 per Mcfe for the three months ended March 31, 2012 as compared to $0.47 per Mcfe for the three months ended March 31, 2011. The increase in lease operating expenses was primarily attributable to both the overall increase in our oil production and the initiation of oil and natural gas production on two new Eagle Ford properties during the first quarter of 2012. During the three months ended March 31, 2012, we completed and initiated oil and natural gas production from four new wells on our Martin Ranch lease in LaSalle County, Texas, necessitating the installation of additional production facilities. While these new facilities were being installed and tested, much of the oil and natural gas was produced through rental test equipment, resulting in higher operating costs during the first quarter of 2012 than we anticipate to be incurred now that the permanent production facilities at Martin Ranch are completed. In addition, we completed and began producing oil and natural gas from two new wells on our Northcut and Sickenius leases in LaSalle and Karnes Counties, respectively, using rental test equipment while more permanent production facilities were being constructed. We also incurred a workover expense of approximately $0.4 million on another of our Eagle Ford wells which is included in lease operating expenses for the three months ended March 31, 2012.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $4.1 million to $11.2 million, or an increase of about 58%, for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased to $2.56 per Mcfe for the three months ended March 31, 2012, or an increase of about 22%, from $2.09 per Mcfe for the three months ended March 31, 2011. This increase in our depletion, depreciation and amortization expenses was attributable to an increase of approximately 29% in our total oil and natural gas production from 3.4 Bcfe to 4.4 Bcfe during the respective time periods, as well as to the higher drilling and completions costs on a per Mcfe basis associated with oil reserves added in the Eagle Ford shale in south Texas as compared with our Haynesville shale natural gas assets in north Louisiana.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $14,000 to approximately $53,000, or an increase of about 34%, for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from a full-cost ceiling impairment was recorded at March 31, 2012. During the quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our operating expenses for the three months ended March 31, 2011.

General and administrative. Our general and administrative expenses increased by $1.2 million to $3.8 million, or an increase of about 45%, for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Our general and administrative expenses increased by 12% on a unit-of-production basis to $0.87 per Mcfe for the three months ended March 31, 2012 as compared to $0.77 per Mcfe for the three months ended March 31, 2011. The increase in our general and administrative expenses was attributable primarily to increased compensation, accounting, legal and other administrative expenses and with becoming a public company during the first quarter of 2012.

Interest expense. For the three months ended March 31, 2012, we incurred total interest expense of approximately $0.6 million. We capitalized approximately $0.3 million of our interest expense on certain qualifying projects for the three months ended March 31, 2012 and expensed the remaining $0.3 million to operations. On February 8, 2012, we repaid our borrowings then outstanding of $123.0 million under our Credit Agreement using a portion of the net proceeds received from our Initial Public Offering. On March 19, 2012, we borrowed $15.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at March 31, 2012 were $15.0 million, and the interest rate on these borrowings was approximately 2.0% per annum. At March 31, 2011, we had borrowings of $40.0 million under our Credit Agreement and incurred interest expense of approximately $0.1 million for the three months ended March 31, 2011.

Interest and other income. Our interest and other income increased by approximately $2,000 to approximately $73,000, or an increase of about 2%, for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The increase in our interest and other income was due primarily to slight increases in both the interest income we received and in the salt water disposal income we received from third parties during the first quarter of 2012 as compared to the first quarter of 2011, although on the whole, this item is an insignificant component of our overall income. Our cash and cash equivalents and certificates of deposit decreased to approximately $3.1 million at March 31, 2012 from approximately $16.5 million at March 31, 2011.

Total income tax provision (benefit). We recorded a total income tax provision of approximately $3.1 million for the three months ended March 31, 2012 as compared to a total income tax benefit of approximately $6.9 million for the three months ended March 31, 2011. The total income tax provision or benefit for both periods reflected only deferred income taxes. We had an effective income tax rate of 44.6% for the three months ended March 31, 2012. Total income tax expense for the three months ended March 31, 2012 differed from amounts computed by applying the U.S. statutory tax rates to income taxes due primarily to state taxes and the impact of an adjustment to the estimated permanent differences between book and taxable income related to stock compensation expense in prior periods. During the quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million. We had a net loss for the three months ended March 31, 2011.

Liquidity and Capital Resources

Prior to the consummation of our Initial Public Offering on February 7, 2012, our primary sources of liquidity were capital contributions from private investors, our cash flows from operations, borrowings under our Credit Agreement and the proceeds from a significant sale of a portion of our assets in 2008. Our primary use of capital has been, and will continue to be during 2012 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings and additional borrowings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

At March 31, 2012, we had cash and certificates of deposits totaling approximately $3.1 million, the borrowing base under our Credit Agreement was $125.0 million and we had $15.0 million of outstanding long-term borrowings and approximately $1.3 million in outstanding letters of credit. These borrowings bore interest at approximately 2.0% per annum. In April 2012, we borrowed an additional $15.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At May 15, 2012, we had $30.0 million of outstanding long-term borrowings and approximately $1.3 million in outstanding letters of credit. These borrowings bore interest at the rate of approximately 2.0% per annum.

While we believe our cash and cash equivalents, together with our anticipated cash flows and future potential borrowings under our Credit Agreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interests and acreage for 2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements for 2013 and subsequent years may require additional sources of financing, which may not be available. On February 28, 2012, our borrowing base was increased to $125.0 million pursuant to a borrowing base redetermination made by the lenders at our request. We expect to request additional redeterminations in accordance with our Credit Agreement as we increase our proved reserves. As a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012 as compared to our cash flows from operations in prior periods, as well as a significant increase in the borrowing base under our Credit Agreement to help fund our 2012 capital expenditure budget.

A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at December 31, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our Credit Agreement (assuming availability under our borrowing base). In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or other preferential securities) in the public market or otherwise. It is likely that any such sales would dilute the ownership interest of our existing shareholders. It is also possible that, to the extent we are not able to obtain additional sources of liquidity, we may modify our planned capital expenditures budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our Credit Agreement.

Our cash flows for the three months ended March 31, 2012 and 2011 are presented below:


	Three Months Ended March 31,
	2012			2011
(In thousands)	(Unaudited)			(Unaudited)
Net cash provided by operating activities	$	5,110		$	12,732
Net cash used in investing activities		(52,764	)		(35,024	)
Net cash provided by financing activities		39,744			15,693

Net change in cash and cash equivalents	$	(7,910	)	$	(6,599	)

Adjusted EBITDA⁽¹⁾	$	21,338		$	10,148

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

Cash Flows Provided by Operating Activities

Net cash provided by operating activities decreased by approximately $7.6 million to $5.1 million for the three months ended March 31, 2012 as compared to net cash provided by operating activities of $12.7 million for the three months ended March 31, 2011. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $21.0 million for the three months ended March 31, 2012 from $10.0 million for the three months ended March 31, 2011. This increase is primarily attributable to the more than 10-fold increase in our oil production to approximately 200,000 Bbl from approximately 19,000 Bbl during the respective periods. A portion of the increase in net cash provided by operating activities also reflects the higher average oil price of $107.57 per Bbl realized during the three months ended March 31, 2012 as compared to an average oil price of $89.11 per Bbl realized during the three months ended March 31, 2011. The decrease in net cash provided by operating activities results from changes in our operating assets and liabilities totaling approximately $18.6 million between March 31, 2012 and March 31, 2011. Our accounts payable and accrued liabilities increased to approximately $49.3 million at March 31, 2012 from approximately $35.8 million at March 31, 2011 due to our increased operating activity in south Texas. Our accounts receivable increased to $21.6 million at March 31, 2012 as compared to $13.0 million at March 31, 2011 due primarily to the increase in our oil production and associated revenues.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict.

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by approximately $17.8 million to $52.8 million for the three months ended March 31, 2012 from $35.0 million for the three months ended March 31, 2011. This increase in net cash used in investing activities is almost entirely attributable to the increase in our oil and natural gas properties capital expenditures for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Our oil and natural gas properties capital expenditures for the three months ended March 31, 2012 were primarily due to our operated drilling and completion activities in the Eagle Ford shale play in south Texas.

Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition, exploration and development activities in 2012 as follows:


	Amount (in millions)
Exploration and development drilling and associated infrastructure	$	284.5
Leasehold acquisition		24.0
Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells		4.5

Total	$	313.0

For further information regarding our anticipated capital expenditure budget in 2012, see “Business – General” in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC. Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and drilling activities, contractual obligations and other factors both within and outside our control.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $39.7 million for the three months ended March 31, 2012, as compared to net cash provided by financing activities of $15.7 million for the three months ended March 31, 2011. The net cash provided by financing activities for the three months ended March 31, 2012 was principally due to the total proceeds from the Initial Public Offering of $146.5 million and incremental borrowings of $25.0 million, offset by the costs of the offering of $11.6 million incurred during the period and by the repayment of $123.0 million in borrowings during the period. We also received approximately $2.7 million from the exercise of stock options during the three months ended March 31, 2012. The net cash provided by financing activities for the three months ended March 31, 2011 was primarily attributable to $15.0 million in borrowings under the Credit Agreement and $0.6 million received from the issuance of common stock.

Non-GAAP Financial Measures

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

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

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


	Three Months Ended March 31,
	2012			2011
(In thousands)
Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):
Net income (loss)	$	3,801		$	(27,596	)
Interest expense		308			106
Total income tax provision (benefit)		3,064			(6,906	)
Depletion, depreciation and amortization		11,205			7,111
Accretion of asset retirement obligations		53			39
Full-cost ceiling impairment		—			35,673
Unrealized loss on derivatives		3,270			1,668
Stock option and grant expense		(374	)		42
Restricted stock expense		11			11

Adjusted EBITDA	$	21,338		$	10,148


	Three Months Ended March 31,
	2012		2011
(In thousands)
Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	5,110	$	12,732
Net change in operating assets and liabilities		15,920		(2,690	)
Interest expense		308		106

Adjusted EBITDA	$	21,338	$	10,148

Our Adjusted EBITDA increased by approximately $11.2 million to approximately $21.3 million, or an increase of approximately 110% for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. This increase in our Adjusted EBITDA is primarily attributable to the increase in our oil production and the associated increase in our oil and natural gas revenues for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.

Credit Agreement

In December 2011, we amended and restated our senior secured revolving Credit Agreement for which Comerica Bank serves as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company is the borrower under the new amended Credit Agreement. Borrowings are secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one of the lenders under the Credit Agreement (or an affiliate thereof) are also secured by the collateral and guaranteed by the subsidiaries of MRC Energy Company.

The amount of the borrowings under our Credit Agreement is limited to the lesser of $400.0 million or the borrowing base, which is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which we have no control. At December 31, 2011, the borrowing base was $125.0 million and we had $113.0 million in outstanding borrowings under the Credit Agreement. In January 2012, we borrowed an additional $10.0 million to finance a portion of our working capital requirements, bringing the then outstanding indebtedness under the Credit Agreement to $123.0 million. Following the completion of our Initial Public Offering, we used a portion of the net proceeds to repay the then outstanding $123.0 million outstanding under our Credit Agreement in February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million pursuant to a special borrowing base redetermination made at our request. This borrowing base increase was determined by our lenders based upon, among other items, the increase in our proved oil and natural gas reserves at December 31, 2011.

In March 2012, we borrowed $15.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At March 31, 2012, we had $15.0 million in borrowings outstanding under the Credit Agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $108.7 million available for additional borrowings. At March 31, 2012, our outstanding borrowings bore interest at approximately 2.0% per annum.

We expect to access future borrowings under our Credit Agreement to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows. During 2012, we also intend to seek additional redeterminations of our borrowing base as a result of, among other items, any increases to our proved oil and natural gas reserves during the year. In April 2012, we borrowed an additional $15.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At May 15, 2012, we had $30.0 million in borrowings outstanding under the Credit Agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $93.7 million available for additional borrowings. At May 15, 2012, our outstanding borrowings bore interest at approximately 2.0% per annum.

Both we and the lenders may each request an unscheduled redetermination of the borrowing base twice at any time during the first year of the Credit Agreement and once between scheduled redetermination dates thereafter. As noted above, we requested one such unscheduled redetermination in February 2012. In the event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of the amount of the increase, which will be determined based on market conditions at the time of the borrowing base increase. If the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, we 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.

If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the weighted average of rates used in overnight federal funds transactions with members of the Federal Reserve System plus 1.0% or (ii) the prime rate for Comerica Bank then in effect or (iii) a daily adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Comerica Bank 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 1.375% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A facility fee of 0.375% to 0.50%, depending on the amounts borrowed, is also paid quarterly in arrears. We include the facility fee in our interest rate calculations and related disclosures.

Key financial covenants under the Credit Agreement require us to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by the consolidated total current liabilities, of 1.0 or greater for all reporting periods beginning March 31, 2012, and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less.

Subject to certain exceptions, our Credit Agreement contains various covenants that limit our, along with our subsidiaries’, ability to take certain actions, including, but not limited to, the following:

•

incur indebtedness or grant liens on any of our 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; and

•

engage in certain asset dispositions, including a sale of all or substantially all of our assets.

•

failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount 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 us or our subsidiaries; and

•

a change of control, as defined in the credit agreement.

At March 31, 2012, we believe that we were in compliance with the terms of our Credit Agreement. We obtained a written extension until May 1, 2012 to comply with a covenant under the Credit Agreement requiring the submission of certain year-end 2011 operating information for the lenders’ use on or before March 1, 2012. We subsequently furnished this information to the lenders prior to May 1, 2012.

Off-Balance Sheet Arrangements

At March 31, 2012, we did not have any off-balance sheet arrangements.

Obligations and Commitments

We had the following material contractual obligations and commitments at March 31, 2012:


	Payments Due by Period
	Total		Less Than 1 Year		1 -3 Years		3 -5 Years		More Than 5 Years
(in thousands)
Contractual Obligations:
Revolving credit borrowings and term loan, including letters of credit⁽¹⁾	$	16,300	$	1,300	$	—	$	15,000	$	—
Office lease		6,243		431		1,150		1,200		3,462
Non-operated drilling commitments⁽²⁾		5,200		5,200		—		—		—
Drilling rig contracts⁽³⁾		9,763		9,763		—		—		—
Employee bonuses		1,240		—		1,240		—		—
Asset retirement obligations		4,475		339		566		461		3,109

Total contractual cash obligations	$	43,221	$	17,033	$	2,956	$	16,661	$	6,571

(1)

At March 31, 2012, we had $15.0 million in revolving borrowings outstanding under our Credit Agreement and approximately $1.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. The revolving borrowings are scheduled to mature in December 2016. These amounts do not include estimated interest on the obligations, because our revolving borrowings have short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods.

(2)

At March 31, 2012, we had outstanding commitments to participate in the drilling and completion of various non-operated wells in the Haynesville and Eagle Ford shales. Our working interests in these wells are small, and most of these wells were in progress at March 31, 2012. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $5.2 million at March 31, 2012, which we expect to incur within the next 12 months.

(3)

During the first quarter of 2012, we extended one of our drilling rig contracts in south Texas for an additional nine months. We terminated a second drilling contract with no termination penalty and entered into a new contract for a higher performance rig with the same drilling rig contractor for a period of one year. Drilling operations under these two contracts began in March 2012. Should we elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under these contracts were approximately $9.8 million at March 31, 2012.

General Outlook and Trends

For the three months ended March 31, 2012, oil prices ranged from a high of approximately $109.77 per Bbl in late February to a low of approximately $96.36 per Bbl in early February, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. Generally, oil prices remained above $100 per Bbl for much of the period. We realized an average oil price of $107.57 per Bbl for our oil production for the three months ended March 31, 2012 as compared to $89.11 per Bbl for the three months ended March 31, 2011. At May 11, 2012, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date closed at $96.13 per Bbl as compared to $98.21 per Bbl at May 11, 2011.

For the three months ended March 31, 2012, natural gas prices ranged from a high of approximately $3.10 per MMBtu in early January to a low of approximately $2.13 per MMBtu in late March, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices continued to decline throughout the first quarter of 2012, reaching their lowest levels in many years. We realized a natural gas price of $2.40 per Mcf ($3.36 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the three months ended March 31, 2012 as compared to $3.65 per Mcf ($4.22 per Mcf including realized gains from natural gas derivatives) for the three months ended March 31, 2011. At May 11, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.51 per MMBtu as compared to $4.18 per MMBtu at May 11, 2011.

The prices we receive for oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and these markets will likely continue to be volatile in the future. Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas we can produce economically. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil and natural gas prices. Even so, decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and natural gas prices, and we may not always employ the optimal hedging strategy. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have an adverse effect on our business, financial condition, results of operations and reserves. This, in turn, may affect the liquidity that can be accessed through our borrowing base under our Credit Agreement and through the capital markets.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our wells in the Eagle Ford shale and the Haynesville shale experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil and natural gas price declines, however, we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves and cash flows.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Except as set forth below, there have been no changes to our market risk since December 31, 2011 as set forth in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

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

We use costless (or zero-cost) collars to manage risks related to changes in oil and natural gas prices. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is initially “costless” to us.

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. Comerica Bank is the single counterparty for all of our derivative instruments. We have evaluated the credit standing of Comerica Bank in determining the fair value of our derivative financial instruments.

At March 31, 2012 and 2011, we used costless collar options to reduce the volatility of natural gas prices on a portion of our future expected natural gas production. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these transactions 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 last day of that contract period. When the settlement price is below the price floor established by these collars, we receive from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by these collars, we pay to Comerica, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume.

The following is a summary of the fair value of our open natural gas costless collar contracts at March 31, 2012.


Commodity	Calculation Period		Notional Quantity		Price Floor		Price Ceiling		Fair Value of Asset
			(MMBtu/month)		($/MMBtu)		($/MMBtu)		(thousands)
Natural Gas		04/01/12 — 12/31/2012		300,000		4.50		5.60	$	5,431
Natural Gas		04/01/12 — 12/31/2012		150,000		4.25		6.17		2,390
Natural Gas		04/01/12 — 07/31/2013		150,000		4.50		5.75		4,005

Total									$	11,826

All of our existing natural gas derivative contracts will expire at varying times during 2012 and 2013.

Between November 2011 and February 2012, we entered into various costless collar transactions to mitigate our exposure to oil price volatility for the first time. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging transactions 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. When the settlement price is below the price floor established by these collars, we receive from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume hedged. When the settlement price is above the price ceiling established by these collars, we pay Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume hedged.

The following table is a summary of the fair value of our open oil costless collar contracts at March 31, 2012.


Commodity	Calculation Period		Notional Quantity		Price Floor		Price Ceiling		Fair Value of Asset (Liability)
			(Bbl/month)		($/Bbl)		($/Bbl)		(thousands)
Oil		04/01/2012 — 12/31/2012		20,000		90.00		104.20	$	(855	)
Oil		04/01/2012 — 12/31/2012		10,000		90.00		108.00		(255	)
Oil		04/01/2012 — 12/31/2012		10,000		90.00		109.50		(205	)
Oil		04/01/2012 — 06/30/2012		20,000		90.00		113.75		(19	)
Oil		04/01/2012 — 12/31/2012		20,000		90.00		111.00		(321	)
Oil		04/01/2012 — 03/31/2013		20,000		90.00		110.00		(543	)
Oil		07/01/2012 — 12/31/2012		20,000		90.00		111.90		(238	)
Oil		07/01/2012 — 12/31/2012		20,000		95.00		116.00		63
Oil		01/01/2013 — 12/31/2013		20,000		85.00		102.25		(1,736	)
Oil		01/01/2013 — 12/31/2013		20,000		90.00		115.00		(82	)
Oil		01/01/2013 — 12/31/2013		20,000		85.00		110.40		(816	)
Oil		01/01/2013 — 12/31/2013		20,000		85.00		108.80		(904	)
Oil		01/01/2013 — 06/30/2014		8,000		90.00		114.00		(2	)
Oil		01/01/2013 — 06/30/2014		12,000		90.00		115.50		100

Total									$	(5,813	)

All of our existing oil derivative contracts will expire at varying times during 2012, 2013 and 2014.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Prior to the completion of our Initial Public Offering, we maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audit for the year ended December 31, 2011, our independent registered public accountants identified and communicated a material weakness related to accounting for stock compensation expense. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely basis.

We have in the past engaged and currently engage outside consultants to review significant or complex accounting issues and calculations. During the quarter ended March 31, 2012, there we no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting except that we hired additional accounting personnel. Since March 31, 2012, we have hired an outside consulting company, Protiviti, Inc., to assist us with our internal audit function, including the evaluation and improvement of our internal control over financial reporting and we formed a disclosure committee.

We became a public company on February 1, 2012 in connection with the completion of our Initial Public Offering. Prior to that date, we were a private company and were not required to file or submit reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and maintained disclosure controls and procedures in accordance with being a private company. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e)) under the Exchange Act was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon this evaluation, as of the end of the period covered by this report, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective because we were not a public company throughout the entire period and because the material weakness described above relating to our internal control over financial reporting was identified.

Part II—Other Information

Item 1. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

Item 1A. Risk Factors

There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

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

On February 6 and 7, 2012, certain directors, officers and employees of the Company exercised previously issued stock options at an exercise price of $9.00 per share for an aggregate of 295,500 shares of common stock, and we received aggregate proceeds of $2,659,500, pursuant to the exemption from registration provided by Rule 701 promulgated pursuant to the Securities Act.

On February 7, 2012, 1,030,700 shares of our former Class B common stock were converted into 1,030,700 shares of common stock pursuant to the terms of the Class B common stock which provided for an automatic conversion of the Class B common stock upon consummation of the Initial Public Offering. The issuance was exempt from registration pursuant to Section 3(a)(9) of the Securities Act.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits


Exhibit Number		Description of Exhibits

3.1		Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 filed on August 12, 2011).

3.2		Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 filed on August 12, 2011).

3.3		Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 filed on August 12, 2011).

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

3.5		Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1 filed on August 12, 2011).

3.6		Amendment to the Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1 filed on August 12, 2011).

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

3.8		Amended and Restated Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on February 13, 2012).

4.1		Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012).

10.1		Nonqualified Stock Option Agreement, dated February 1, 2012, between Matador Resources Company and Wade Massad (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 7, 2012).

10.2		Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011).

10.3		Form of Incentive Stock Option Agreement relating to the Matador Resources Company 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011).

10.4		Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith).


Exhibit Number		Description of Exhibits

10.5		Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011).

10.6		Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith).

10.7		Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith).

10.8		Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (filed herewith).

10.9		Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (filed herewith).

10.10		Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (filed herewith).

10.11		First Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated April 16, 2012 (filed herewith).

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

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

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

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

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

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

101*		The following financial information from Matador Resources Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Condensed Consolidated Statement of Stockholders’ Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited) and (v) the Notes to Condensed Consolidated Financial Statements (submitted electronically herewith).

In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this quarterly report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

SIGNATURES

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


		MATADOR RESOURCES COMPANY

Date: May 15, 2012	By:	/s/ Joseph Wm. Foran
		Joseph Wm. Foran
		Chairman, President and Chief Executive Officer

Date: May 15, 2012	By:	/s/ David E. Lancaster
		David E. Lancaster
		Executive Vice President, Chief Operating Officer and Chief Financial Officer