Matador Resources Co - FORM 10-Q - May 11, 2015

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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, 2015
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-35410
 _________________________________________________________  
Matador Resources Company
(Exact name of registrant as specified in its charter)
  _________________________________________________________ 
 
Texas
27-4662601
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
5400 LBJ Freeway, Suite 1500
Dallas, Texas
75240
(Address of principal executive offices)
(Zip Code)
(972) 371-5200
(Registrant’s telephone number, including area code)
 _________________________________________________________  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     x  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
x
 
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
 
Smaller reporting company
 
¨
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 6, 2015, there were 85,370,330 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, 2015
INDEX
 
Page


Part I – FINANCIAL INFORMATION
Item 1. Financial Statements
Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED
(In thousands, except par value and share data)
 
March 31,
2015
 
December 31,
2014
ASSETS
 
 
 
Current assets
 
 
 
Cash
$
6,061

 
$
8,407

Restricted cash
991

 
609

Accounts receivable
 
 
 
Oil and natural gas revenues
26,349

 
28,976

Joint interest billings
12,924

 
6,925

Other
7,114

 
9,091

Derivative instruments
47,011

 
55,549

Lease and well equipment inventory
1,718

 
1,212

Prepaid expenses
3,025

 
2,554

Total current assets
105,193

 
113,323

Property and equipment, at cost
 
 
 
Oil and natural gas properties, full-cost method
 
 
 
Evaluated
1,785,208

 
1,617,913

Unproved and unevaluated
449,042

 
264,419

Other property and equipment
64,610

 
43,472

Less accumulated depletion, depreciation and amortization
(717,330
)
 
(603,732
)
Net property and equipment
1,581,530

 
1,322,072

Other assets
 
 
 
Other assets
703

 
896

Total other assets
703

 
896

Total assets
$
1,687,426

 
$
1,436,291

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
61,476

 
$
17,526

Accrued liabilities
128,845

 
109,502

Royalties payable
11,932

 
14,461

Note payable
11,982

 
—

Advances from joint interest owners
1,378

 
—

Deferred income taxes
16,462

 
19,751

Income taxes payable
—

 
444

Other current liabilities
123

 
103

Total current liabilities
232,198

 
161,787

Long-term liabilities
 
 
 
Borrowings under Credit Agreement
410,000

 
340,000

Asset retirement obligations
13,275

 
11,640

Derivative instruments
19

 
—

Deferred income taxes
106,649

 
53,783

Other long-term liabilities
2,451

 
2,540

Total long-term liabilities
532,394

 
407,963

Commitments and contingencies (Note 11)


 


Shareholders’ equity
 
 
 
Preferred stock - Series A, $0.01 par value, 2,000,000 shares authorized; 150,000 and zero shares issued and outstanding, respectively
1

 
—

Common stock - $0.01 par value, 80,000,000 shares authorized; 76,844,899 and 73,373,744 shares issued; and 76,780,402 and 73,342,777 shares outstanding, respectively
769

 
734

Additional paid-in capital
830,824

 
724,819

Retained earnings
90,621

 
140,855

Treasury stock, at cost, 64,497 and 30,967 shares, respectively
—

 
—

Total Matador Resources Company shareholders’ equity
922,215

 
866,408

Non-controlling interest in subsidiary
619

 
133

Total shareholders' equity
922,834

 
866,541

Total liabilities and shareholders’ equity
$
1,687,426

 
$
1,436,291


The accompanying notes are an integral part of these financial statements.
3

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED
(In thousands, except per share data)
 
Three Months Ended 
 March 31,
 
2015
 
2014
Revenues
 
 
 
Oil and natural gas revenues
$
62,465

 
$
78,931

Realized gain (loss) on derivatives
18,504

 
(1,843
)
Unrealized loss on derivatives
(8,557
)
 
(3,108
)
Total revenues
72,412

 
73,980

Expenses
 
 
 
Production taxes and marketing
7,049

 
6,006

Lease operating
13,046

 
9,351

Depletion, depreciation and amortization
46,470

 
24,030

Accretion of asset retirement obligations
112

 
117

Full-cost ceiling impairment
67,127

 
—

General and administrative
13,413

 
7,219

Total expenses
147,217

 
46,723

Operating (loss) income
(74,805
)
 
27,257

Other income (expense)
 
 
 
Net loss on asset sales and inventory impairment
(97
)
 
—

Interest expense
(2,070
)
 
(1,396
)
Interest and other income
384

 
38

Total other expense
(1,783
)
 
(1,358
)
(Loss) income before income taxes
(76,588
)
 
25,899

Income tax (benefit) provision
 
 
 
Current
—

 
1,275

Deferred
(26,390
)
 
8,261

Total income tax (benefit) provision
(26,390
)
 
9,536

Net (loss) income
(50,198
)
 
16,363

Net income attributable to non-controlling interest in subsidiary
(36
)
 
—

Net (loss) income attributable to Matador Resources Company shareholders
$
(50,234
)
 
$
16,363

Earnings (loss) per common share
 
 
 
Basic
$
(0.68
)
 
$
0.25

Diluted
$
(0.68
)
 
$
0.25

Weighted average common shares outstanding
 
 
 
Basic
73,819

 
65,684

Diluted
73,819

 
66,229


The accompanying notes are an integral part of these financial statements.
4

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY - UNAUDITED
(In thousands)
For the Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total shareholders' equity attributable to Matador Resources Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-controlling interest in subsidiary
 
Total shareholders' equity
 
Common Stock
 
Preferred Stock
 
Additional
paid-in capital
 
Retained earnings
 
Treasury Stock
 
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Shares
 
Amount
 
 
 
Balance at January 1, 2015
73,374

 
$
734

 
—

 
$
—

 
$
724,819

 
$
140,855

 
31

 
$
—

 
$
866,408

 
$
133

 
$
866,541

Issuance of common stock
3,300

 
33

 
—

 
—

 
71,445

 
—

 
—

 
—

 
71,478

 
—

 
71,478

Issuance of preferred stock
—

 
—

 
150

 
1

 
32,489

 
—

 
—

 
—

 
32,490

 
—

 
32,490

Common stock issued to Board members and advisors
6

 
—

 
—

 
—

 
4

 
—

 
—

 
—

 
4

 
—

 
4

Stock options expense related to equity-based awards
—

 
—

 
—

 
—

 
1,019

 
—

 
—

 
—

 
1,019

 
—

 
1,019

Stock options exercised
3

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock issued
163

 
2

 
—

 
—

 
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeited
—

 
—

 
—

 
—

 
—

 
—

 
33

 
—

 
—

 
—

 
—

Restricted stock and restricted stock units expense
—

 
—

 
—

 
—

 
1,050

 
—

 
—

 
—

 
1,050

 
—

 
1,050

Capital contribution to less than wholly owned subsidiary
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
450

 
450

Current period net (loss) income
—

 
—

 
—

 
—

 
—

 
(50,234
)
 
—

 
—

 
(50,234
)
 
36

 
(50,198
)
Balance at March 31, 2015
76,846

 
$
769

 
150

 
$
1

 
$
830,824

 
$
90,621

 
64

 
$
—

 
$
922,215

 
$
619

 
$
922,834


The accompanying notes are an integral part of these financial statements.
5

Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED
(In thousands)
 
Three Months Ended 
 March 31,
 
2015
 
2014
Operating activities
 
 
 
Net (loss) income
$
(50,198
)
 
$
16,363

Adjustments to reconcile net (loss) income to net cash provided by operating activities
 
 
 
Unrealized loss on derivatives
8,557

 
3,108

Depletion, depreciation and amortization
46,470

 
24,030

Accretion of asset retirement obligations
112

 
117

Full-cost ceiling impairment
67,127

 
—

Stock-based compensation expense
2,337

 
1,795

Deferred income tax (benefit) provision
(26,390
)
 
8,261

Net loss on asset sales and inventory impairment
97

 
—

Changes in operating assets and liabilities

 

Accounts receivable
2,140

 
(6,941
)
Lease and well equipment inventory
(112
)
 
(31
)
Prepaid expenses
(364
)
 
(424
)
Other assets
193

 
(466
)
Accounts payable, accrued liabilities and other current liabilities
45,703

 
(16,540
)
Royalties payable
(2,907
)
 
1,597

Advances from joint interest owners
1,378

 
—

Income taxes payable
(444
)
 
1,275

Other long-term liabilities
(353
)
 
(199
)
Net cash provided by operating activities
93,346

 
31,945

Investing activities


 


Oil and natural gas properties capital expenditures
(127,440
)
 
(92,891
)
Expenditures for other property and equipment
(14,241
)
 
(1,007
)
Business combination, net of cash acquired
(24,028
)
 
—

Restricted cash in less than wholly-owned subsidiary
(383
)
 
—

Net cash used in investing activities
(166,092
)
 
(93,898
)
Financing activities


 


Borrowings under Credit Agreement
70,000

 
70,000

Proceeds from stock options exercised
—

 
6

Capital commitment from non-controlling interest in subsidiary
450

 
—

Taxes paid related to net share settlement of stock-based compensation
(50
)
 
—

Net cash provided by financing activities
70,400

 
70,006

Increase (decrease) in cash
(2,346
)
 
8,053

Cash at beginning of period
8,407

 
6,287

Cash at end of period
$
6,061

 
$
14,340

 
 
 
 
Supplemental disclosures of cash flow information (Note 12)


 



The accompanying notes are an integral part of these financial statements.
6

Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED
NOTE 1 - NATURE OF OPERATIONS
Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas and the Eagle Ford shale play in South Texas. The Company also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates
The unaudited condensed consolidated financial statements of Matador and its wholly-owned and majority-owned 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, 2014 filed with the SEC (the “Annual Report”). The Company proportionately consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. 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, 2015, consolidated results of operations for the three months ended March 31, 2015 and 2014, consolidated changes in shareholders’ equity for the three months ended March 31, 2015 and consolidated cash flows for the three months ended March 31, 2015 and 2014. Amounts as of December 31, 2014 are derived from the audited consolidated financial statements in the Annual Report.
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, natural gas and natural gas liquids prices, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, oil, natural gas and natural gas liquids 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 interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
Reclassifications
Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.
Restricted Cash
Restricted cash represents the cash held by our less-than-wholly-owned subsidiary. By contractual agreement, the cash in this account is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of this less-than-wholly-owned subsidiary, which disposes of limited quantities of Company and third-party salt water.

7
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 certain general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized approximately $1.6 million and $0.9 million of its general and administrative costs for the three months ended March 31, 2015 and 2014, respectively. The Company capitalized approximately $1.0 million and $0.7 million of its interest expense for the three months ended March 31, 2015 and 2014, respectively.
The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:
(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus
(b) unproved and unevaluated property costs not being amortized, plus
(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less
(d) income tax effects related to the properties involved.
Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The need for a full-cost ceiling impairment is required to be assessed on a quarterly basis. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.
The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period, and the guidelines further dictate that a 10% discount factor be used to determine the present value of future net revenues. For the period from April 2014 through March 2015, these average oil and natural gas prices were $79.21 per barrel (“Bbl”) and $3.882 per million British thermal units (“MMBtu”), respectively. For the period from April 2013 through March 2014, these average oil and natural gas prices were $94.92 per Bbl and $3.989 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were 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, 2015 and 2014, 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, for the oil and natural gas reserves estimates at March 31, 2015, 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, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $42.8 million. As a result, the Company recorded an impairment charge of $67.1 million to its net capitalized costs and a deferred income tax credit of $24.3 million related to the full-cost ceiling limitation at March 31, 2015. These charges are reflected in the Company’s unaudited condensed consolidated statement of operations for the three months ended March 31, 2015. Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at March 31, 2014, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost

8
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

ceiling. As a result, the Company recorded no impairment to its net capitalized costs for the three months ended March 31, 2014.
As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheet, as well as the corresponding consolidated shareholders’ equity, but it has no impact on the Company’s consolidated net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.
 Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.
Allocation of Purchase Price in Business Combinations
As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.
Earnings (Loss) Per Common Share
The Company reports basic earnings (loss) per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
The following table sets forth the computation of diluted weighted average common shares outstanding for the three months ended March 31, 2015 and 2014 (in thousands).
 
Three Months Ended 
 March 31,
2015
 
2014
Weighted average common shares outstanding
 
 
 
Basic
73,819

 
65,684

Dilutive effect of options, restricted stock units and preferred shares
—

 
545

Diluted weighted average common shares outstanding
73,819

 
66,229

A total of 2.5 million options to purchase shares of the Company’s common stock, 0.2 million restricted stock units and 150,000 preferred shares were excluded from the calculations above for the three months ended March 31, 2015 because their effects were anti-dilutive. Additionally, 0.8 million restricted shares, which are participating securities, were excluded from the calculations above for the three months ended March 31, 2015 as the security holders do not have the obligation to share in the losses of the Company.
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.

9
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

Recent Accounting Pronouncements
Revenue from Contracts with Customers. In May 2014, the FASB issued Accounting Standards Update, or ASU, 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. ASU 2014-09 will become effective for fiscal years beginning after December 15, 2016, i.e., in the Company’s first fiscal quarter of 2017. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements.
Interest - Imputation of Interest. In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs, which requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. The guidance requires retrospective application in financial statements issued for fiscal years beginning after December 31, 2015 and interim periods within fiscal years beginning after December 15, 2016. The impact of the adoption of this ASU on the Company’s financial statements will be to reduce total assets and total liabilities by the carrying value of unamortized debt issuance costs at the time of adoption.
NOTE 3 – BUSINESS COMBINATION
On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through which it obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross (18,200 net) acres strategically located between Matador’s existing acreage in its Ranger and Rustler Breaks prospect areas through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Matador paid an additional $3.0 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. As a result of the HEYCO Merger, Matador incurred deferred tax liabilities of approximately $76.0 million and assumed other liabilities of approximately $4.6 million. The HEYCO Merger was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. During the three months ended March 31, 2015, the Company incurred approximately $2.2 million of transaction costs associated with the HEYCO Merger. These costs are recorded in general and administrative expenses for the three months ended March 31, 2015. The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage. The producing wells acquired in the HEYCO Merger did not have a material impact on our revenues or results of operations. Therefore, pro forma financial information for the HEYCO Merger is not presented as the effects are not material to the Company’s consolidated results. Included in the Statement of Operations for the three months ended March 31, 2015 is revenue attributable to the operations acquired in the HEYCO Merger of approximately $0.7 million.

 

10
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 3 - BUSINESS COMBINATION - Continued


The preliminary allocation of the consideration given related to this business combination, which is subject to change, was as follows.
Consideration given
 
   Cash
$
24,648

   Preferred shares issued
32,490

   Common shares issued
71,478

      Total consideration given
$
128,616

 Allocation of purchase price
 
   Cash acquired
$
620

   Accounts receivable
3,536

   Inventory
180

   Other current assets
106

   Oil and natural gas properties
 
      Evaluated oil and natural gas properties
22,044

      Unproved oil and unevaluated natural gas properties
194,686

   Accounts payable
(2,551
)
   Accrued liabilities
(11
)
   Current note payable
(11,982
)
   Asset retirement obligations
(2,046
)
   Deferred tax liabilities incurred
(75,966
)
      Net assets acquired
$
128,616

NOTE 4 - EQUITY
As discussed in Note 3, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Preferred Stock) in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. Each share of Series A Preferred Stock would be entitled to ten votes on each matter submitted to Matador’s shareholders for vote. Beginning on August 27, 2015 and until such time as the Series A Preferred Stock was converted to common stock, the holders would be entitled to a quarterly dividend of $1.80 per share. Neither the issuance of the Series A Preferred Stock nor the common stock issued in connection with the HEYCO Merger were registered under the Securities Act of 1933, as amended, and neither the Series A Preferred Stock nor such common stock may be offered or sold in the United States absent such registration or an applicable exemption from registration requirements. As part of the HEYCO Merger, the Company entered into a registration rights agreement with HEYCO Energy Group, Inc. providing certain demand and piggyback registration rights, with demand registration rights exercisable beginning on February 27, 2016.
On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. The 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015, following shareholder approval of the amendment to our Amended and Restated Certificate of Formation.
On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting direct offering costs totaling approximately $1.6 million, the Company received net proceeds of approximately $187.1 million. The Company used a portion of the net proceeds to repay $85.0 million in outstanding borrowings under its revolving credit facility (see Note 6), which amounts may be reborrowed in accordance with the terms of that facility. The remaining $102.1 million of net proceeds is being used to fund a portion of the Company’s working capital expenditures, including the possible

11
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 4 - EQUITY - Continued


addition of a third drilling rig in the Permian Basin as early as late summer 2015 and targeted acquisitions of additional acreage in the Permian Basin, as well as in the Eagle Ford shale and the Haynesville shale, and for other general working capital needs. Pending such uses, the Company plans to invest the remaining proceeds in short-term marketable securities.
All shares of treasury stock outstanding at March 31, 2015 and December 31, 2014 represent forfeitures of non-vested restricted stock awards.
NOTE 5 - ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations for the three months ended March 31, 2015 (in thousands).
 
 
Beginning asset retirement obligations
$
11,951

Liabilities incurred during period
2,404

Liabilities settled during period
(221
)
Revisions in estimated cash flows
(703
)
Accretion expense
112

Ending asset retirement obligations
13,543

Less: current asset retirement obligations(1)
(268
)
Long-term asset retirement obligations
$
13,275

 _______________
(1)
Included in accrued liabilities in the Company’s unaudited condensed consolidated balance sheet at March 31, 2015.
NOTE 6 - DEBT
Credit Agreement
On September 28, 2012, the Company entered into a third amended and restated credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million. The Credit Agreement matures December 29, 2016. MRC Energy Company is the borrower under the Credit Agreement and is a subsidiary of Matador that, at March 31, 2015, directly or indirectly owns the ownership interests in the Company’s other operating subsidiaries other than one less-than-wholly-owned subsidiary and MRC Delaware Resources, LLC. Borrowings are secured by mortgages on substantially all of the Company’s proved oil and natural gas properties and by the equity interests of certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company.
The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the second quarter of 2015, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at December 31, 2014, and as a result, on April 6, 2015, the Company received notice that the borrowing base under the Credit Agreement would be reaffirmed at $450.0 million, and the conforming borrowing base would be reaffirmed at $375.0 million. Pursuant to an amendment to the Credit Agreement entered into concurrently with the issuance of $400.0 million of senior unsecured notes on April 14, 2015 discussed herein, the borrowing base was reduced to the conforming borrowing base of $375.0 million.
In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. Total deferred loan costs were $1.6 million at March 31, 2015, and these costs are being amortized over the term of the agreement, which approximates the amortization of these costs using the effective interest method. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional

12
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 6 - DEBT - Continued

collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.
At March 31, 2015, the Company had $410.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. For the three months ended March 31, 2015, the Company’s outstanding borrowings bore interest at an effective interest rate of approximately 2.9% per annum. On April 14, 2015, using a portion of the net proceeds from the senior unsecured notes offering discussed herein, the Company repaid $380.0 million of its outstanding borrowings under the Credit Agreement. From April 14, 2015 through April 23, 2015, the Company borrowed $55.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures and the acquisition of additional leasehold interests. On April 24, 2015, using a portion of the net proceeds from the April 2015 public offering of common stock discussed herein, the Company repaid the $85.0 million of outstanding borrowings under the Credit Agreement. At May 6, 2015, the Company had no borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement.
As of March 31, 2015, if the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 2.75% 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 LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 3.75% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less.
Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:
•
incur indebtedness or grant liens on any of the Company’s assets;
•
enter into commodity hedging agreements;
•
declare or pay dividends, distributions or redemptions;
•
merge or consolidate;
•
make any loans or investments;
•
engage in transactions with affiliates;
•
engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and
•
take certain actions with respect to the Company’s senior unsecured notes.
If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:
•
failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;
•
failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
•
bankruptcy or insolvency events involving the Company or its subsidiaries; and
•
a change of control, as defined in the Credit Agreement.
At March 31, 2015, the Company believes that it was in compliance with the terms of the Credit Agreement.

13
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 6 - DEBT - Continued

Senior Unsecured Notes
On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Notes”). The Notes are Matador’s senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds of approximately $392.0 million, after deducting the initial purchasers’ discounts and estimated offering expenses, were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year. The Notes are guaranteed on a senior unsecured basis by all of Matador’s wholly-owned subsidiaries.
On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve month period beginning on April 15 of the years indicated.
Year
 
Redemption Price
2018
 
105.156%
2019
 
103.438%
2020
 
101.719%
2021 and thereafter
 
100.000%
At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.
In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price equal to the sum of:
(i) the principal amount thereof, plus
(ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the indenture governing the Notes (the “Indenture”)) plus 50 basis points, over (b) the principal amount of such Notes, plus
(iii) accrued and unpaid interest, if any, to the redemption date.
Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:
•
incur or guarantee additional debt or issue certain types of preferred stock;
•
pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness;
•
transfer or sell assets;
•
make certain investments;
•
create certain liens;
•
enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company;
•
consolidate, merge or transfer all or substantially all of its assets;
•
engage in transactions with affiliates; and
•
create unrestricted subsidiaries.
In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that,

14
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 6 - DEBT - Continued

taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:
•
default for 30 days in the payment when due of interest on the Notes;
•
default in the payment when due of the principal of, or premium, if any, on the Notes;
•
failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets;
•
failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;
•
failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;
•
payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more;
•
failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days;
•
any subsidiary guarantee by a guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and
•
certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.
Current Note Payable
In connection with the HEYCO Merger, Matador assumed a note payable to PlainsCapital Bank in the amount of $12.5 million pursuant to which approximately $12.0 million of indebtedness was outstanding. The outstanding indebtedness was repaid on April 14, 2015 using a portion of the net proceeds from the Notes offering, and the related credit agreement and all associated obligations of Matador were terminated.
NOTE 7 - INCOME TAXES
The Company had an effective tax rate of 34.4% for the three months ended March 31, 2015. Total income tax benefit for the three months ended March 31, 2015 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax loss due primarily to the impact of permanent differences between book and taxable income. The total income tax benefit of $26.4 million for the three months ended March 31, 2015 includes $24.3 million of deferred income tax benefit resulting from the full-cost ceiling impairment. Based upon its projections for the remainder of 2014, the Company anticipated incurring a small alternative minimum tax (“AMT”) liability for the year ending December 31, 2014, the proportionate share of which was recorded as the current income tax provision for the three months ended March 31, 2014. The Company had an effective tax rate of 36.8% for the three months ended March 31, 2014. Total income tax expense for the three months ended March 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income due primarily to the impact of permanent differences between book and taxable income.
NOTE 8 - STOCK-BASED COMPENSATION
In January 2015, the Company granted awards of 113,289 shares of restricted stock and options to purchase 607,995 shares of the Company’s common stock at an exercise price of $22.01 to certain of its employees. The fair value of these awards was approximately $8.4 million. All of these awards vest over a term of three years.
NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS
From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless collars and swap contracts. The Company records derivative financial instruments in its consolidated balance sheet as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations as an unrealized gain or unrealized loss. The fair value of the

15
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. RBC, Comerica Bank, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for the Company’s commodity derivatives at March 31, 2015. The Company has considered the credit standings of the counterparties in determining the fair value of its 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 one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume.
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 settlement date of that contract period. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume.
The Company has entered into various swap contracts to mitigate its exposure to fluctuations in natural gas liquids (“NGL”) prices, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to the Company pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume.
At March 31, 2015, the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2015 and 2016.
At March 31, 2015, the Company had various swap contracts open and in place to mitigate its exposure to NGL price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and fixed price. Each contract is set to expire at varying times during 2015.

16
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following is a summary of the Company’s open costless collar contracts for oil and natural gas and open swap contracts for NGL at March 31, 2015.
Commodity
Calculation Period
 
Notional
Quantity
(Bbl/month)
 
Price
Floor
($/Bbl)
 
Price
Ceiling
($/Bbl)
 
Fair Value of
Asset
(Liability)
(thousands)
Oil
04/01/2015 - 12/31/2015
 
20,000

 
80.00

 
100.00
 
$
4,974

Oil
04/01/2015 - 12/31/2015
 
20,000

 
80.00

 
101.00
 
4,978

Oil
04/01/2015 - 12/31/2015
 
20,000

 
83.00

 
96.12
 
5,499

Oil
04/01/2015 - 12/31/2015
 
20,000

 
83.00

 
97.00
 
5,499

Oil
04/01/2015 - 12/31/2015
 
20,000

 
85.00

 
99.00
 
5,855

Oil
04/01/2015 - 12/31/2015
 
20,000

 
85.00

 
100.00
 
5,855

Oil
04/01/2015 - 12/31/2015
 
20,000

 
85.00

 
105.10
 
5,855

Total open oil costless collar contracts
 
 
 
 
 
 
 
38,515

Commodity
Calculation Period
 
Notional
Quantity
(MMBtu/month)
 
Price
Floor
($/MMBtu)
 
Price
Ceiling
($/MMBtu)
 
Fair Value of
Asset
(Liability)
(thousands)
Natural Gas
04/01/2015 - 10/31/2015
 
150,000

 
2.75

 
3.19

 
154

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
2.75

 
3.05

 
66

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
2.75

 
3.15

 
89

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
2.75

 
3.11

 
80

Natural Gas
04/01/2014 - 12/31/2015
 
300,000

 
2.88

 
3.18

 
490

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.36

 
891

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.45

 
892

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.60

 
895

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.65

 
888

Natural Gas
04/01/2015 - 12/31/2015
 
200,000

 
3.75

 
5.04

 
1,799

Natural Gas
04/01/2015 - 12/31/2015
 
100,000

 
3.75

 
5.34

 
900

Natural Gas
01/01/2016 - 12/31/2016
 
200,000

 
2.75

 
3.50

 
(65
)
Total open natural gas costless collar contracts
 
 
 
 
 
 
 
7,079

Commodity
Calculation Period
 
Notional Quantity
(Gal/month)
 
Fixed Price
($/Gal)
 
Fair Value of Asset (Liability)
(thousands)
Propane
04/01/2015 - 12/31/2015
 
150,000

 
1.000

 
626

Propane
04/01/2015 - 12/31/2015
 
100,000

 
1.030

 
444

Propane
04/01/2015 - 12/31/2015
 
68,000

 
1.073

 
328

   Total open NGL swap contracts
 
 
 
 
 
 
1,398

Total open derivative financial instruments
 
 
 
 
 
 
$
46,992

These derivative financial instruments are subject to master netting arrangements within specific commodity types, i.e., oil, natural gas and NGL, by counterparty. Derivative financial instruments with Counterparty A are not subject to master netting across commodity types, while derivative financial instruments with Counterparties B, C and D allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheet.

17
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

 The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of March 31, 2015 (in thousands).
Derivative Instruments
Gross
amounts of
recognized
assets
 
Gross amounts
netted in the condensed
consolidated
balance sheet
 
Net amounts of
assets
presented in the condensed
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
   Current assets
$
11,372

 
$
(17
)
 
$
11,355

 
$
—

   Other assets
—

 
—

 
—

 
—

Counterparty B

 

 

 
 
   Current assets
7,683

 
(19
)
 
7,664

 
—

   Other assets
—

 
—

 
—

 
—

Counterparty C

 

 

 
 
   Current assets
22,186

 
(950
)
 
21,236

 
—

   Other assets
359

 
(359
)
 
—

 
—

Counterparty D
 
 
 
 
 
 
 
   Current assets
6,764

 
(8
)
 
6,756

 
—

   Other assets
—

 
—

 
—

 
—

Total
$
48,364

 
$
(1,353
)
 
$
47,011

 
$
—

The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of March 31, 2015 (in thousands). 
Derivative Instruments
Gross
amounts of
recognized
liabilities
 
Gross amounts
netted in the condensed
consolidated
balance sheet
 
Net amounts of
liabilities
presented in the condensed
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
   Current liabilities
$
17

 
$
(17
)
 
$
—

 
$
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty B

 

 

 

   Current liabilities
19

 
(19
)
 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty C

 

 

 

   Current liabilities
950

 
(950
)
 
—

 
—

   Other liabilities
378

 
(359
)
 
19

 
—

Counterparty D
 
 
 
 
 
 
 
   Current liabilities
8

 
(8
)
 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Total
$
1,372

 
$
(1,353
)
 
$
19

 
$
—


18
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

 The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of December 31, 2014 (in thousands).
Derivative Instruments
Gross
amounts of
recognized
assets
 
Gross amounts
netted in the
condensed
consolidated
balance sheet
 
Net amounts of
assets
presented in the condensed
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
   Current assets
$
13,437

 
$
(157
)
 
$
13,280

 
$
—

   Other assets
—

 
—

 
—

 
—

Counterparty B
 
 
 
 
 
 
 
   Current assets
8,759

 
(116
)
 
8,643

 
—

   Other assets
—

 
—

 
—

 
—

Counterparty C
 
 
 
 
 
 
 
   Current assets
25,685

 
(368
)
 
25,317

 
—

   Other assets
—

 
—

 
—

 
—

Counterparty D
 
 
 
 
 
 
 
Current assets
8,374

 
(65
)
 
8,309

 
—

Other assets
—

 
—

 
—

 
—

Total
$
56,255

 
$
(706
)
 
$
55,549

 
$
—

The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of December 31, 2014 (in thousands).
Derivative Instruments
Gross
amounts of
recognized
liabilities
 
Gross amounts
netted in the
condensed
consolidated
balance sheet
 
Net amounts of
liabilities
presented in the
condensed
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
   Current liabilities
$
157

 
$
(157
)
 
$
—

 
$
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty B

 

 

 
 
   Current liabilities
116

 
(116
)
 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty C
 
 
 
 
 
 
 
   Current liabilities
368

 
(368
)
 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty D
 
 
 
 
 
 
 
   Current liabilities
65

 
(65
)
 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Total
$
706

 
$
(706
)
 
$
—

 
$
—


19
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.
 
 
 
Three Months Ended 
 March 31,
Type of Instrument
Location in Condensed Consolidated Statement of Operations
 
2015
 
2014
Derivative Instrument
 
 
 
 
 
Oil
Revenues: Realized gain (loss) on derivatives
 
$
14,433

 
$
(942
)
Natural Gas
Revenues: Realized gain (loss) on derivatives
 
3,600

 
(589
)
NGL
Revenues: Realized gain (loss) on derivatives
 
471

 
(312
)
Realized gain (loss) on derivatives
 
18,504

 
(1,843
)
Oil
Revenues: Unrealized loss on derivatives
 
(6,464
)
 
(2,050
)
Natural Gas
Revenues: Unrealized loss on derivatives
 
(1,563
)
 
(1,267
)
NGL
Revenues: Unrealized (loss) gain on derivatives
 
(530
)
 
209

Unrealized loss on derivatives
 
(8,557
)
 
(3,108
)
Total
 
 
$
9,947

 
$
(4,951
)
NOTE 10 - 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 with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3
Unobservable inputs that are not corroborated by market data. 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, 2015 and December 31, 2014, the carrying values reported on the unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, note payable, advances from joint interest owners, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities.
At March 31, 2015 and December 31, 2014, 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.

20
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 10 - 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, 2015 and December 31, 2014 (in thousands). 
 
Fair Value Measurements at
March 31, 2015 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Oil, natural gas and NGL derivatives
$
—

 
$
47,011

 
$
—

 
$
47,011

Oil, natural gas and NGL derivatives
—

 
(19
)
 
—

 
(19
)
Total
$
—

 
$
46,992

 
$
—

 
$
46,992

 
Fair Value Measurements at
December 31, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
   Oil, natural gas and NGL derivatives
$
—

 
$
55,549

 
$
—

 
$
55,549

           Total
$
—

 
$
55,549

 
$
—

 
$
55,549

Additional disclosures related to derivative financial instruments are provided in Note 9. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2.
The Company accounts for additions and revisions to asset retirement obligations and lease and well equipment inventory when adjusted for impairment at fair value on a non-recurring basis and has determined that these fair value measurements should be classified at Level 3. 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, 2015 and December 31, 2014 (in thousands).
  
Fair Value Measurements at
March 31, 2015 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$
—

 
$
—

 
$
(1,701
)
 
$
(1,701
)
Total
$
—

 
$
—

 
$
(1,701
)
 
$
(1,701
)
 
Fair Value Measurements at
December 31, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$
—

 
$
—

 
$
(3,985
)
 
$
(3,985
)
Total
$
—

 
$
—

 
$
(3,985
)
 
$
(3,985
)
No impairment to any equipment was recorded during the three months ended March 31, 2015 and December 31, 2014. Reconciliations for the Company’s asset retirement obligations at March 31, 2015 are provided in Note 5.

21
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 11 - COMMITMENTS AND CONTINGENCIES

Natural Gas and NGL Processing and Transportation Commitments
Effective September 1, 2012, the Company entered into a firm five-year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period.
Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company’s remaining aggregate undiscounted minimum commitments under this agreement are $5.3 million at March 31, 2015. The Company paid $1.3 million and $1.2 million in processing and transportation fees under this agreement during the three months ended March 31, 2015 and 2014, respectively.
Other Commitments
The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for one year or less, although the Company has recently begun to enter into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were until recently experiencing heavy demand for drilling rigs. The Company would incur a termination obligation if the Company elected to terminate a contract and the drilling contractor were unable to secure work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $45.0 million at March 31, 2015.
The Company entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in Loving County, Texas in 2014. This plant is expected to process a portion of the Company’s natural gas produced from certain of its wells in the Permian Basin, as well as third-party natural gas once the plant is completed. Total commitments under this contract are $17.0 million, and the Company made payments totaling $5.2 million during the three months ended March 31, 2015. The Company made no payments under this contract during the three months ended March 31, 2014. The plant is scheduled to be completed and placed in service in the third quarter of 2015.
At March 31, 2015, the Company had agreed to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed, the Company will have undiscounted minimum outstanding aggregate commitments for its participation in these wells of approximately $18.6 million at March 31, 2015, which the Company expects to incur within the next few months.
Legal Proceedings
The Company is a defendant in several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

22
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 12 - SUPPLEMENTAL DISCLOSURES


Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at March 31, 2015 and December 31, 2014 (in thousands).
 
March 31,
2015
 
December 31, 2014
Accrued evaluated and unproved and unevaluated property costs
$
96,432

 
$
86,259

Accrued support equipment and facilities costs
11,302

 
4,290

Accrued stock-based compensation
325

 
—

Accrued lease operating expenses
7,942

 
9,034

Accrued interest on borrowings under Credit Agreement
292

 
206

Accrued asset retirement obligations
268

 
311

Accrued partners’ share of joint interest charges
6,516

 
3,767

Other
5,768

 
5,635

Total accrued liabilities
$
128,845

 
$
109,502

Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the three months ended March 31, 2015 and 2014 (in thousands).
 
Three Months Ended 
 March 31,
 
2015
 
2014
Cash paid for interest expense, net of amounts capitalized
$
1,990

 
$
1,269

Asset retirement obligations related to mineral properties
1,507

 
1,715

Asset retirement obligations related to support equipment and facilities
32

 
111

Increase in liabilities for oil and natural gas properties capital expenditures
8,654

 
42,012

Increase in liabilities for support equipment and facilities
6,865

 
437

Issuance of restricted stock units for Board and advisor services
142

 
96

Issuance of common stock for advisor services
4

 
6

Stock-based compensation expense recognized as liability
263

 
677

Transfer of inventory from oil and natural gas properties
310

 
107

NOTE 13 - SUBSIDIARY GUARANTORS
Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the Company issued the Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries” and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). As of March 31, 2015, the Guarantor Subsidiaries are 100% owned by Matador, and any subsidiaries of Matador other than the Notes Guarantor Subsidiaries are minor. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. As of March 31, 2015, the Company had no outstanding debt securities.

23

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2014 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.
For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “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: the integration of the assets, employees and operations of Harvey E. Yates Company following its merger with one of our wholly-owned subsidiaries on February 27, 2015, changes in oil or natural gas prices, the success of our drilling program, the timing and amount of planned capital expenditures, having sufficient cash flow from operations together with available borrowing capacity under our revolving credit facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:
•
our business strategy;
•
our reserves;
•
our technology;
•
our cash flows and liquidity;
•
our financial strategy, budget, projections and operating results;
•
our oil and natural gas realized prices;
•
the timing and amount of future production of oil and natural gas;
•
the availability of drilling and production equipment;
•
the availability of oil field labor;
•
the amount, nature and timing of capital expenditures, including future exploration and development costs;
•
the availability and terms of capital;
•
our drilling of wells;
•
government regulation and taxation of the oil and natural gas industry;

24

•
our marketing of oil and natural gas;
•
our exploitation projects or property acquisitions;
•
the merger of our wholly-owned subsidiary with Harvey E. Yates Company;
•
our costs of exploiting and developing our properties and conducting other operations;
•
general economic conditions;
•
competition in the oil and natural gas industry;
•
the effectiveness of our risk management and hedging activities;
•
environmental liabilities;
•
counterparty credit risk;
•
developments in oil-producing and natural gas-producing countries;
•
our future operating results;
•
estimated future reserves and the present value thereof;
•
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical; and
•
other factors discussed in the Annual Report.
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
Overview
We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas and the Eagle Ford shale play in South Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.
First Quarter Highlights
Quarterly production results for the first quarter of 2015 were the best in our Company’s history. Our total oil equivalent production for the first quarter of 2015 was 2.1 million BOE, and our average daily oil equivalent production for the first quarter of 2015 was 23,513 BOE per day, of which 11,206 Bbl per day, or 48%, was oil and 73.8 MMcf per day, or 52%, was natural gas. Our average daily oil production of 11,206 Bbl per day, our total natural gas production of 6.6 Bcf and our average daily natural gas production of 73.8 MMcf per day for the first quarter of 2015 were also record quarterly results.
During the first quarter of 2015, our oil and natural gas revenues were $62.5 million, a decrease of 21% from oil and natural gas revenues of $78.9 million during the first quarter of 2014. This decrease was attributable to a sharp decline in the weighted average oil and natural gas prices we realized to $43.37 per Bbl and $2.82 per Mcf, respectively, in the first quarter of 2015 from weighted average oil and natural gas prices of $96.34 per Bbl and $6.20 per Mcf, respectively, in the first quarter of 2014. The decrease in our oil and natural gas revenues was partially offset by the 53% increase in our oil production to 1.0 million Bbl in the first quarter of 2015, as compared to 661,000 Bbl produced in the first quarter of 2014. This increase in oil production was primarily a result of our ongoing development activities in the Eagle Ford shale, as well as better-than-expected initial production contributions from newly drilled wells in the Permian Basin. For the three months ended March 31, 2015, our Adjusted EBITDA was $50.1 million, a decrease of 11% from Adjusted EBITDA of $56.3 million during the three months ended March 31, 2014. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a

25

reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for 2015, see “— Results of Operations” below.
On February 27, 2015, we completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through which we obtained certain oil and natural gas producing properties and undeveloped acreage strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas in Lea and Eddy Counties, New Mexico (the “HEYCO Merger”). The approximately 58,600 gross (18,200 net) acres we obtained in the HEYCO Merger increased our acreage position in the Permian Basin to approximately 152,400 gross (85,400 net) acres at March 31, 2015.
As consideration for the HEYCO Merger, we paid approximately $21.6 million in cash, assumed debt obligations of approximately $12.0 million (the “Assumed Indebtedness”) and issued 3,300,000 shares of the Company’s common stock and 150,000 shares of a new series of the Company’s convertible preferred stock (the “Series A Preferred Stock”) to HEYCO Energy Group, Inc. In addition, we paid $3.0 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. As a result of the HEYCO Merger, we incurred deferred tax liabilities of approximately $76.0 million and assumed other liabilities of approximately $4.6 million. Pursuant to the terms of the merger agreement, 125,000 of the 150,000 shares of Series A Preferred Stock issued upon the closing of the HEYCO Merger were placed into escrow to satisfy post-closing adjustments to the merger consideration for certain title or environmental defects on the HEYCO assets. Each share of Series A Preferred Stock converted into ten shares of our common stock on April 6, 2015 following the vote and approval by our shareholders of an amendment to our Amended and Restated Certificate of Formation to increase the number of shares of authorized common stock (the “Charter Amendment”) and the receipt of evidence of the filing of the Charter Amendment with the Texas Secretary of State.
At March 31, 2015, we had borrowings outstanding of $410.0 million and $0.6 million in letters of credit issued under our third amended and restated credit agreement (the “Credit Agreement”). On April 6, 2015, we received notice that the borrowing base under our Credit Agreement would be reaffirmed at $450.0 million, and the conforming borrowing base would be reaffirmed at $375.0 million, based on our lenders’ review of our proved oil and natural gas reserves at December 31, 2014. On April 14, 2015, using a portion of the net proceeds from our senior unsecured notes offering discussed below, we repaid $380.0 million in outstanding borrowings under our Credit Agreement. From April 14, 2015 through April 23, 2015, we borrowed $55.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures and the acquisition of additional leasehold interests. On April 24, 2015, using a portion of the net proceeds from our April 2015 public offering of common stock discussed below, we repaid the $85.0 million of outstanding borrowings under our Credit Agreement. At May 6, 2015, we had no borrowings outstanding under our Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to our Credit Agreement.
On April 14, 2015, we issued $400.0 million of our 6.875% senior notes due 2023 (the “Notes”). The Notes are our senior unsecured obligations and were issued at par value. The net proceeds of approximately $392.0 million, after deducting the initial purchasers’ discounts and estimated offering expenses, were used to pay down $380.0 million in outstanding borrowings under our Credit Agreement, which amounts may be reborrowed in accordance with the terms of that facility, and $12.0 million in Assumed Indebtedness.
On April 21, 2015, we completed a public offering of 7,000,000 shares of our common stock. After deducting direct offering costs totaling approximately $1.6 million, we received net proceeds of approximately $187.1 million. We used a portion of the net proceeds to repay $85.0 million in outstanding borrowings under our Credit Agreement, which amounts may be reborrowed in accordance with the terms of that facility. The remaining $102.1 million of net proceeds is being used to fund a portion of our capital expenditures, including the possible addition of a third drilling rig in the Permian Basin as early as late summer 2015 and targeted acquisitions of additional acreage in the Permian Basin, as well as in the Eagle Ford shale and the Haynesville shale, and for other general working capital needs. Pending such uses, we plan to invest the remaining proceeds in short-term marketable securities.
We were operating five drilling rigs, two rigs in the Eagle Ford and three rigs in the Permian Basin, at the beginning of 2015, but had reduced our operated drilling rigs to two by the end of the first quarter of 2015, with both operating in the Permian Basin. We are currently running two drilling rigs in the Permian Basin, one in Loving County, Texas and the other in Eddy County, New Mexico, and currently plan to operate at least two drilling rigs in the Permian Basin for the remainder of 2015. We are now considering adding a third drilling rig in the Permian Basin as early as late summer 2015 depending on commodity prices and improved well economics resulting from higher recoveries, realized savings from various operating efficiencies and cost savings from vendors. We have completed our planned operated drilling and completion activities in the Eagle Ford shale for 2015. We expect to continue to participate in several non-operated Haynesville shale wells drilled by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) and other operating partners during the remainder of 2015. We expect to fund our remaining 2015 capital expenditure budget through a combination of cash on hand, operating cash flows, borrowings under our revolving credit facility (assuming availability under our borrowing base), the net proceeds from the

26

offering of the Notes described above and the offering of common stock described above, potential joint ventures and the potential sale of assets or acreage. At March 31, 2015, we had incurred $159.0 million, or approximately 45%, of our anticipated 2015 capital expenditure budget of $350.0 million (excluding capital expenditures associated with the HEYCO Merger).
During the first quarter of 2015, we completed and began producing oil and natural gas from five gross (3.5 net) wells in the Permian Basin, including four gross (3.4 net) operated wells and one gross (0.1 net) non-operated well. We completed two operated wells in our Wolf prospect area in Loving County, Texas — the Barnett 90-TTT-B01-WF #201H and the Barnett 90-TTT-B01-WF #205H wells — and two operated wells in our Rustler Breaks prospect area in Eddy County, New Mexico — the Guitar 10-24S-28E RB #202H and the Tiger 14-24S-28E RB #224H wells. The Barnett 90-TTT-B01-WF #201H and the Barnett 90-TTT-B01-WF #205H wells began producing in February, and the Guitar 10-24S-28E RB #202H and the Tiger 14-24S-28E RB #224H wells were completed and began producing in late March. As a result, these four wells did not contribute fully to production volumes for the first quarter of 2015.
Nonetheless, our Permian Basin production has increased significantly in the past year. Our total Permian Basin production for the first quarter of 2015 was 3,546 BOE per day, consisting of 2,467 Bbl of oil per day and 6.5 MMcf of natural gas per day, more than triple our Permian Basin total production of 1,066 BOE per day, consisting of 904 Bbl of oil per day and 1.0 MMcf of natural gas per day, in the first quarter of 2014. The Permian Basin contributed approximately 22% of our daily oil production and approximately 9% of our daily natural gas production in the first quarter of 2015, as compared to only about 12% of our daily oil production and approximately 4% of our daily natural gas production in the first quarter of 2014.
In the Wolf prospect area in Loving County, Texas, the Barnett 90-TTT-B01-WF #205H and the Barnett 90-TTT-B01-WF #201H wells were drilled on 80-acre spacing from the same drilling pad. The Barnett 90-TTT-B01-WF #205H was drilled and completed in the Wolfcamp “A”/“Y” sand, just below the “A”/“X” sand, at approximately 11,000 feet true vertical depth. This was our first test of the Wolfcamp “A”/“Y” interval in the Wolf prospect area. This well had a completed lateral length of 4,376 feet, and we completed the well with 17 frac stages, including approximately 140,000 barrels of fluid and 7.1 million pounds of sand. The Barnett 90 TTT-B01-WF #201H was drilled and completed in the Wolfcamp “A”/“X” sand at the top of the Wolfcamp formation at approximately 10,900 feet true vertical depth. This is the zone that most of our horizontal completions in the Wolf prospect have targeted thus far. This well had a completed lateral length of 4,318 feet, and we completed the well with 21 frac stages, including approximately 175,000 barrels of fluid and 8.9 million pounds of sand. During its 24-hour initial potential test, the Barnett 90-TTT-WF #205H well, the Wolfcamp “A”/“Y” completion, flowed 1,377 BOE per day (54% oil), consisting of 738 Bbl of oil per day and 3.8 MMcf of natural gas per day, at 3,475 pounds per square inch (“psi”) on a 26/64th inch choke. We believe this initial test of the Wolfcamp “A”/“Y” sand establishes this zone as another potential completion horizon for us in the upper Wolfcamp in the Wolf prospect area. During its 24-hour initial potential test, the Barnett 90-TTT-WF #201H, the Wolfcamp “A”/“X” completion, flowed 1,268 BOE per day (57% oil), consisting of 720 Bbl of oil per day and 3.3 MMcf of natural gas per day, at 3,225 psi on a 26/64th inch choke. We plan to monitor the performance of these two 80-acre spaced wells closely to determine if these two zones can be effectively developed in a staggered “W”-type pattern on 80-acre spacing going forward. We are currently running one drilling rig in our Wolf prospect area and plan to continue running one drilling rig in this area for the remainder of 2015.
In the Rustler Breaks prospect area in Eddy County, New Mexico, the Guitar 10-24S-28E RB #202H and the Tiger 14-24S-28E RB #224H wells tested two new horizons within the Wolfcamp formation. The Guitar 10-24S-28E RB #202H well was drilled and completed in the Wolfcamp “A”/“X-Y” sand at the top of the Wolfcamp “A” formation at approximately 9,550 feet true vertical depth. This well had a completed lateral length of 4,232 feet, and we completed the well with 18 frac stages, including approximately 164,000 barrels of fluid and 8.3 million pounds of sand. During its 24-hour initial potential test, the Guitar 10-24S-28E RB #202H well flowed 1,273 BOE per day (79% oil), consisting of 1,008 Bbl of oil per day and 1.6 MMcf of natural gas per day, at 2,190 psi on a 26/64th inch choke. To our knowledge, this was one of the first wells to test the Wolfcamp “A”/“X-Y” sand horizontally in southern Eddy County, New Mexico. This interval is the stratigraphic equivalent of the highly productive Wolfcamp “A”/“X-Y” intervals being completed in our Wolf prospect in Loving County, Texas. The Tiger 14-24S-28E RB #224H well was drilled and completed in the lower portion of the Wolfcamp “B” formation at approximately 10,500 feet true vertical depth. This Wolfcamp “B” target is approximately 300 feet lower stratigraphically than the zone from which the Rustler Breaks 12-24S-27E RB#224H well (formerly the Rustler Breaks 12-24-27 #1H), our initial Wolfcamp “B” well in the Rustler Breaks prospect area, is producing. The Tiger 14-24S-28E RB #224H well had a completed lateral length of 4,376 feet, and we completed the well with 21 frac stages, including approximately 170,000 barrels of fluid and 8.8 million pounds of sand. During its 24-hour initial potential test, the well flowed 1,525 BOE per day (43% oil), consisting of 650 Bbl of oil per day and 5.3 MMcf of natural gas per day, at 3,900 psi on a 26/64th inch choke. This successful test of the lower portion of the Wolfcamp “B” was also encouraging because we believe that the upper and lower portions of the Wolfcamp “B” may be even more effectively developed in a staggered “W”-type pattern on 80-acre spacing. We are currently running one rig in the Rustler Breaks prospect area and plan to continue running one rig in Eddy and Lea Counties, New Mexico for the remainder of 2015.

27

During the first quarter of 2015, we completed and began producing oil and natural gas from 14 gross (14.0 net) Eagle Ford wells, all of which were operated wells. We completed four Eagle Ford wells on our Pena lease in La Salle County, two wells on our Thiel Martin lease in La Salle County and eight wells on our Bishop-Brogan lease in Karnes County, Texas. The Pena wells began producing in early-to-mid-January, the Thiel Martin wells began producing in early February and the Bishop-Brogan wells began producing in late March. As a result, these wells did not contribute fully to production volumes for the first quarter of 2015. Since March 31, 2015, we have completed and placed on production three gross (3.0 net) additional Eagle Ford wells. We have now completed our planned operated Eagle Ford drilling and completion operations for 2015. At December 31, 2014, over 95% of our Eagle Ford acreage was either held by production or not burdened by lease expirations until 2016 or later.
The eight wells on our Bishop-Brogan properties located adjacent to our Danysh/Pawelek leases on our central acreage in Karnes County were developed using the batch drilling method in groups of four wells each on approximately 40-acre spacing and were completed with our Generation 7 fracture treatment. The eight wells had average initial production rates of 902 BOE per day (88% oil) on 14/64th inch chokes at an average flowing casing pressure of 3,105 psi, making them some of the best wells we have drilled in the Eagle Ford shale play. The combination of operational efficiencies from batch development and other drilling improvements and service cost reductions resulted in an average well cost of approximately $5.3 million for these Bishop-Brogan wells, which was almost 20% below original estimates and resulted in aggregate savings of about $9 million compared to the costs originally budgeted for these eight wells. We intend to use many of these improved drilling and completion practices in our Wolf, Ranger, Rustler Breaks and Twin Lakes prospect areas in Southeast New Mexico and West Texas as we continue our delineation and development efforts in our Permian Basin operations.
We continue to be pleased with the performance of various Haynesville shale wells being completed and placed on production by Chesapeake in our Elm Grove properties in Northwest Louisiana. Chesapeake placed seven gross (1.2 net) additional Haynesville shale wells on production in the first quarter of 2015. These wells had initial production rates ranging from 12 to 15 MMcf of natural gas per day (gross) at flowing tubing pressures of 6,000 to 8,000 psi. Further, Chesapeake drilled and completed these wells for an average of $7 to $8 million, below our expectations. Along with the 14 gross (3.3 net) Haynesville wells Chesapeake placed on production in 2014, these new wells have contributed to a significant increase in our natural gas production rate from approximately 58 MMcf of natural gas per day in the fourth quarter of 2014 to approximately 80 MMcf of natural gas per day in the last two weeks of March 2015. Our average daily natural gas production from the Haynesville increased more than five-fold year-over-year from about 9.5 MMcf per day in the first quarter of 2014 to 50.6 MMcf per day in the first quarter of 2015.
At March 31, 2015, our estimated total proved oil and natural gas reserves were 79.3 million BOE, including 32.5 million Bbl of oil and 280.5 Bcf of natural gas, with a PV-10 of $1.07 billion and a Standardized Measure of $949.2 million. At December 31, 2014, our estimated proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, and at March 31, 2014, our estimated proved oil and natural gas reserves were 54.6 million BOE, including 16.9 million Bbl of oil and 225.9 Bcf of natural gas. Our proved oil reserves of 32.5 million Bbl at March 31, 2015 increased 92%, as compared to 16.9 million Bbl at March 31, 2014, and 34%, as compared to 24.2 million Bbl at December 31, 2014. These reserves estimates were based on evaluations prepared by our engineering staff and, with respect to the reserves at March 31, 2015 and December 31, 2014, have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
We realized a weighted average oil price of $43.37 per Bbl for the three months ended March 31, 2015, as compared to $96.34 per Bbl for the three months ended March 31, 2014. Most of our Eagle Ford oil production in South Texas is sold based on a Louisiana Light Sweet oil price index less transportation costs. Oil production from our properties in the Permian Basin in Southeast New Mexico and West Texas is sold on a West Texas Intermediate at Midland oil price index less transportation costs. We realized a weighted average natural gas price of $2.82 per Mcf for the three months ended March 31, 2015, as compared to $6.20 per Mcf for the three months ended March 31, 2014. This price reflects an uplift as a result of natural gas liquids we produce with our Eagle Ford and Permian Basin natural gas production. Our natural gas production from the Haynesville shale is mostly dry natural gas and does not receive a price uplift as a result of natural gas liquids. See “— Results of Operations” below for more information on our oil and natural gas prices realized during the first quarter of 2015.
Estimated Proved Reserves
The following table sets forth our estimated total proved oil and natural gas reserves at March 31, 2015, December 31, 2014 and March 31, 2014. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Eagle Ford shale and the Permian Basin, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. These reserves estimates were based on evaluations prepared by our engineering staff and, with respect to the reserves estimates at March 31, 2015 and December 31, 2014, have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and

28

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 would be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total proved reserves are estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
 
March 31, 2015
 
December 31,
2014
 
March 31, 2014
Estimated Proved Reserves Data: (1) (2)
 
 
 
 
 
Estimated proved reserves:
 
 
 
 
 
Oil (MBbl)(3)
32,506

 
24,184

 
16,919

Natural Gas (Bcf)(4)
280.5

 
267.1

 
225.9

Total (MBOE)(5)
79,262

 
68,693

 
54,563

Estimated proved developed reserves:
 
 
 
 
 
Oil (MBbl)(3)
15,889

 
14,053

 
8,999

Natural Gas (Bcf)(4)
104.7

 
102.8

 
56.1

Total (MBOE)(5)
33,340

 
31,185

 
18,349

Percent developed
42.1
%
 
45.4
%
 
33.6
%
Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MBbl)(3)
16,617

 
10,131

 
7,920

Natural Gas (Bcf)(4)
175.8

 
164.3

 
169.8

Total (MBOE)(5)
45,922

 
37,508

 
36,214

PV-10(6) (in millions)
$
1,070.1

 
$
1,043.4

 
$
739.8

Standardized Measure(7) (in millions)
$
949.2

 
$
913.3

 
$
653.6

_______________
(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 2014 through March 2015 were $79.21 per Bbl for oil and $3.882 per MMBtu for natural gas, for the period from January 2014 through December 2014 were $91.48 per Bbl for oil and $4.350 per MMBtu for natural gas and for the period from April 2013 through March 2014 were $94.92 per Bbl for oil and $3.989 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
(3)
One thousand barrels of oil.
(4)
One billion cubic feet of natural gas.
(5)
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(6)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at March 31, 2015, December 31, 2014 and March 31, 2014 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at March 31, 2015, December 31, 2014 and March 31, 2014 were, in millions, $120.9, $130.1 and $86.2, respectively.
(7)
Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

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At March 31, 2015, our estimated total proved oil and natural gas reserves were 79.3 million BOE, including 32.5 million Bbl of oil and 280.5 Bcf of natural gas, with a PV-10 of $1.07 billion and a Standardized Measure of $949.2 million. At December 31, 2014, our estimated total proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, and at March 31, 2014, our estimated total proved oil and natural gas reserves were 54.6 million BOE, including 16.9 million Bbl of oil and 225.9 Bcf of natural gas. Our proved oil reserves of 32.5 million Bbl at March 31, 2015 increased 34%, as compared to 24.2 million Bbl at December 31, 2014, and 92%, as compared to 16.9 million Bbl at March 31, 2014. During the three months ended March 31, 2015, our proved developed reserves increased 7% from 31.2 million BOE at December 31, 2014 to 33.3 million BOE at March 31, 2015. Year-over-year, our proved developed reserves increased 82% from 18.3 million BOE at March 31, 2014. At March 31, 2015, approximately 42% of our total proved reserves were proved developed reserves, 41% of our total proved reserves were oil and 59% of our total proved reserves were natural gas.
There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in the Annual Report.
Critical Accounting Policies
Other than as described below, there have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.
Allocation of Purchase Price in Business Combinations
As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.
Recent Accounting Pronouncements
Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update, or ASU, 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard also requires expanded disclosures surrounding revenue recognition and is intended to improve and converge with international standards the financial reporting requirements for revenue from contracts with customers. ASU 2014-09 will become effective for fiscal years beginning after December 15, 2016, i.e., in our first fiscal quarter of 2017. We are currently evaluating the impact, if any, of the adoption of this ASU on our consolidated financial statements.
Interest - Imputation of Interest. In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs, which requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. The guidance requires retrospective application in financial statements issued for fiscal years beginning after December 31, 2015 and interim periods within fiscal years beginning after December 15, 2016. The impact of the adoption of this ASU on the Company’s financial statements will be to reduce total assets and total liabilities by the carrying value of unamortized debt issuance costs at the time of adoption.


30

Results of Operations
Revenues
The following table summarizes our revenues and production data for the periods indicated:
 
Three Months Ended 
 March 31,
 
2015
 
2014
(Unaudited)
 
(Unaudited)
Operating Data:
 
 
 
Revenues (in thousands):(1)
 
 
 
Oil
$
43,736

 
$
63,674

Natural gas
18,729

 
15,257

Total oil and natural gas revenues
62,465

 
78,931

Realized gain (loss) on derivatives
18,504

 
(1,843
)
Unrealized loss on derivatives
(8,557
)
 
(3,108
)
Total revenues
$
72,412

 
$
73,980

Net Production Volumes:(1)
 
 
 
Oil (MBbl)(2)
1,009

 
661

Natural gas (Bcf)(3)
6.6

 
2.5

Total oil equivalent (MBOE)(4)
2,116

 
1,071

Average daily production (BOE/d)(5)
23,513

 
11,904

Average Sales Prices:
 
 
 
Oil, with realized derivatives (per Bbl)
$
57.68

 
$
94.91

Oil, without realized derivatives (per Bbl)
$
43.37

 
$
96.34

Natural gas, with realized derivatives (per Mcf)
$
3.43

 
$
5.83

Natural gas, without realized derivatives (per Mcf)
$
2.82

 
$
6.20

_________________
(1)
We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with extracted natural gas liquids are included with our natural gas revenues.
(2)
One thousand barrels of oil.
(3)
One billion cubic feet of natural gas.
(4)
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)
Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Three Months Ended March 31, 2015 as Compared to Three Months Ended March 31, 2014
Oil and natural gas revenues. Our oil and natural gas revenues decreased by $16.5 million to $62.5 million, or a decrease of 21%, for the three months ended March 31, 2015, as compared to $78.9 million for the three months ended March 31, 2014. This decrease in oil and natural gas revenues includes a decrease in our oil revenues of $19.9 million and an increase in our natural gas revenues of $3.5 million for the three months ended March 31, 2015, as compared to the three months ended March 31, 2014. Our oil revenues decreased by $19.9 million, or 31%, to $43.7 million for the three months ended March 31, 2015, as compared to $63.7 million for the three months ended March 31, 2014. Our oil production increased by 53% to 1.0 million Bbl of oil in the first quarter of 2015, or 11,206 Bbl of oil per day, as compared to 661,000 Bbl of oil in the first quarter of 2014, or 7,344 Bbl of oil per day. This increase in oil production was primarily a result of our ongoing development activities in the Eagle Ford shale, as well as better-than-expected initial production contributions from newly drilled wells in the Permian Basin. The decrease in oil revenues resulted from a lower oil price realized in the first quarter of 2015 of $43.37 per Bbl as compared to $96.34 per Bbl realized for the first quarter of 2014. This decrease in realized oil price was partially offset by the increase in our oil production of 53% in the first quarter of 2015, as compared to the first quarter of 2014. Our natural gas revenues increased by $3.5 million, or 23%, to $18.7 million for the three months ended March 31, 2015, as compared to $15.3 million for the three months ended March 31, 2014. The increase in natural gas revenues resulted from an increase in natural gas production of 170% to 6.6 Bcf for the three months ended March 31, 2015, as compared to 2.5 Bcf for the three months ended March 31, 2014, which was offset by a lower weighted average natural gas price of $2.82 per Mcf realized during the first quarter of 2015, as compared to a weighted average natural gas price of $6.20 per Mcf realized during the first quarter of 2014. The increase in natural gas production was primarily attributable to the increased natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production on Matador’s Elm Grove properties in Northwest

31

Louisiana during the latter half of 2014 and into 2015, but also includes increased natural gas production associated with Matador’s operations in the Permian Basin, particularly in the Wolf Prospect area.
Realized gain (loss) on derivatives. Our realized gain on derivatives was $18.5 million for the three months ended March 31, 2015, as compared to a realized loss of $1.8 million for the three months ended March 31, 2014. For the three months ended March 31, 2015, we realized a net gain of $14.4 million, $3.6 million and $0.5 million attributable to our oil, natural gas and natural gas liquids (“NGL”) derivative contracts, respectively. For the three months ended March 31, 2014, we realized a net loss of $0.9 million, $0.6 million and $0.3 million attributable to our oil, natural gas and NGL derivative contracts, respectively. The realized gain on our oil, natural gas and NGL derivative contracts between the respective periods was attributable to lower commodity prices for the three months ended March 31, 2015, as compared to the three months ended March 31, 2014. The realized gain on our oil and natural gas derivative contracts during the three months ended March 31, 2015 resulted from oil prices that were lower than the floor prices of our oil costless collar contracts and natural gas prices that were lower than the floor prices of several of our natural gas costless collar contracts. The realized gain on our NGL derivative contracts during the three months ended March 31, 2015 resulted from NGL prices that were lower than the fixed prices of our NGL swap contracts. We realized a gain of approximately $34.36 per Bbl and $0.77 per MMBtu hedged on all of our oil and natural gas derivative contracts, respectively, during the three months ended March 31, 2015, as compared to a loss of $1.49 per Bbl and $0.22 per MMBtu hedged on all of our oil and natural gas derivative contracts, respectively, during the three months ended March 31, 2014. The average floor prices of our oil costless collar contracts were $83.00 per Bbl and $87.73 per Bbl as of March 31, 2015 and March 31, 2014, respectively. The average ceiling prices of our oil costless collar contracts were $99.75 pe