Matador Resources Co - FORM 10-Q - August 7, 2014

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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 June 30, 2014
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
 
¨
 
Accelerated filer
 
x
 
 
 
 
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 August 6, 2014, there were 73,339,315 shares of the registrant’s common stock, par value $0.01 per share, outstanding.


MATADOR RESOURCES COMPANY
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2014
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)
 
June 30,
2014
 
December 31,
2013
ASSETS
 
 
 
Current assets
 
 
 
Cash
$
14,635

 
$
6,287

Accounts receivable
 
 
 
Oil and natural gas revenues
33,493

 
25,823

Joint interest billings
9,925

 
4,785

Other
1,594

 
1,066

Derivative instruments
22

 
19

Deferred income taxes
4,294

 
1,636

Lease and well equipment inventory
954

 
785

Prepaid expenses
2,427

 
1,771

Total current assets
67,344

 
42,172

Property and equipment, at cost
 
 
 
Oil and natural gas properties, full-cost method
 
 
 
Evaluated
1,278,003

 
1,090,656

Unproved and unevaluated
277,949

 
194,306

Other property and equipment
32,219

 
29,910

Less accumulated depletion, depreciation and amortization
(524,822
)
 
(468,995
)
Net property and equipment
1,063,349

 
845,877

Other assets
 
 
 
Derivative instruments
171

 
173

Other assets
2,577

 
2,108

Total other assets
2,748

 
2,281

Total assets
$
1,133,441

 
$
890,330

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
18,541

 
$
25,358

Accrued liabilities
105,129

 
63,987

Royalties payable
13,687

 
7,798

Derivative instruments
10,264

 
2,692

Income taxes payable
3,219

 
404

Other current liabilities
88

 
88

Total current liabilities
150,928

 
100,327

Long-term liabilities
 
 
 
Borrowings under Credit Agreement
150,000

 
200,000

Asset retirement obligations
9,723

 
7,309

Derivative instruments
1,025

 
253

Deferred income taxes
30,942

 
10,929

Other long-term liabilities
3,581

 
2,588

Total long-term liabilities
195,271

 
221,079

Commitments and contingencies (Note 10)


 


Shareholders’ equity
 
 
 
Common stock - $0.01 par value, 80,000,000 shares authorized; 74,657,951 and 66,958,867 shares issued; and 73,327,906 and 65,652,690 shares outstanding, respectively
747

 
670

Additional paid-in capital
732,587

 
548,935

Retained earnings
64,673

 
30,084

Treasury stock, at cost, 1,330,045 and 1,306,177 shares, respectively
(10,765
)
 
(10,765
)
Total shareholders’ equity
787,242

 
568,924

Total liabilities and shareholders’ equity
$
1,133,441

 
$
890,330


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 June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
Revenues
 
 
 
 
 
 
 
Oil and natural gas revenues
$
99,054

 
$
58,179

 
$
177,986

 
$
117,498

Realized (loss) gain on derivatives
(2,913
)
 
254

 
(4,756
)
 
646

Unrealized (loss) gain on derivatives
(5,234
)
 
7,526

 
(8,342
)
 
2,701

Total revenues
90,907

 
65,959

 
164,888

 
120,845

Expenses
 
 
 
 
 
 
 
Production taxes and marketing
9,116

 
4,451

 
15,122

 
8,548

Lease operating
11,704

 
10,140

 
21,055

 
21,040

Depletion, depreciation and amortization
31,797

 
20,234

 
55,827

 
48,466

Accretion of asset retirement obligations
123

 
80

 
241

 
161

Full-cost ceiling impairment
—

 
—

 
—

 
21,229

General and administrative
8,100

 
4,149

 
15,319

 
8,751

Total expenses
60,840

 
39,054

 
107,564

 
108,195

Operating income
30,067

 
26,905

 
57,324

 
12,650

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

 
(192
)
 
—

 
(192
)
Interest expense
(1,616
)
 
(1,609
)
 
(3,012
)
 
(2,880
)
Interest and other income
409

 
47

 
447

 
115

Total other expense
(1,207
)
 
(1,754
)
 
(2,565
)
 
(2,957
)
Income before income taxes
28,860

 
25,151

 
54,759

 
9,693

Income tax provision
 
 
 
 
 
 
 
Current
1,539

 
32

 
2,814

 
78

Deferred
9,095

 
—

 
17,356

 
—

Total income tax provision
10,634

 
32

 
20,170

 
78

Net income
$
18,226

 
$
25,119

 
$
34,589

 
$
9,615

Earnings per common share:
 
 
 
 

 

Basic
$
0.27

 
$
0.45

 
$
0.52

 
$
0.17

Diluted
$
0.26

 
$
0.45

 
$
0.51

 
$
0.17

Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
68,531

 
55,839

 
67,108

 
55,729

Diluted
69,220

 
55,937

 
67,771

 
55,819


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 Six Months Ended June 30, 2014
 
Common Stock
 
Additional
Paid-In Capital
 
Retained Earnings
 
Treasury Stock
 
 
 
Shares
 
Amount
 
 
 
Shares
 
Amount
 
Total
Balance at January 1, 2014
66,959

 
$
670

 
$
548,935

 
$
30,084

 
1,306

 
$
(10,765
)
 
$
568,924

Issuance of common stock
7,500

 
75

 
181,800

 
—

 
—

 
—

 
181,875

Cost to issue equity
—

 
—

 
(590
)
 
—

 
—

 
—

 
(590
)
Common stock issued to Board advisors
17

 
—

 
10

 
—

 
—

 
—

 
10

Stock options expense related to equity-based awards
—

 
—

 
1,067

 
—

 
—

 
—

 
1,067

Stock options exercised
2

 
—

 
6

 
—

 
—

 
—

 
6

Liability-based stock option awards settled
—

 
—

 
10

 
—

 
—

 
—

 
10

Restricted stock issued
180

 
2

 
(2
)
 
—

 
—

 
—

 
—

Restricted stock forfeited
—

 
—

 
(18
)
 
—

 
24

 
—

 
(18
)
Restricted stock and restricted stock units expense
—

 
—

 
1,369

 
—

 
—

 
—

 
1,369

Current period net income
—

 
—

 
—

 
34,589

 
—

 
—

 
34,589

Balance at June 30, 2014
74,658

 
$
747

 
$
732,587

 
$
64,673

 
1,330

 
$
(10,765
)
 
$
787,242


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)
 
Six Months Ended 
 June 30,
 
2014
 
2013
Operating activities
 
 
 
Net income
$
34,589

 
$
9,615

Adjustments to reconcile net income to net cash provided by operating activities
 
 
 
Unrealized loss (gain) on derivatives
8,342

 
(2,701
)
Depletion, depreciation and amortization
55,827

 
48,466

Accretion of asset retirement obligations
241

 
161

Full-cost ceiling impairment
—

 
21,229

Stock-based compensation expense
3,629

 
1,524

Deferred income tax provision
17,356

 
—

Net loss on asset sales and inventory impairment
—

 
192

Changes in operating assets and liabilities

 

Accounts receivable
(13,338
)
 
1,763

Lease and well equipment inventory
(36
)
 
280

Prepaid expenses
(656
)
 
(215
)
Other assets
(468
)
 
(117
)
Accounts payable, accrued liabilities and other current liabilities
(517
)
 
4,615

Royalties payable
5,890

 
(206
)
Advances from joint interest owners
—

 
(1,515
)
Income taxes payable
2,814

 
78

Other long-term liabilities
(198
)
 
743

Net cash provided by operating activities
113,475

 
83,912

Investing activities


 


Oil and natural gas properties capital expenditures
(234,335
)
 
(173,989
)
Expenditures for other property and equipment
(1,884
)
 
(2,081
)
Purchases of certificates of deposit
—

 
(61
)
Maturities of certificates of deposit
—

 
230

Net cash used in investing activities
(236,219
)
 
(175,901
)
Financing activities


 


Repayments of borrowings under Credit Agreement
(180,000
)
 
—

Borrowings under Credit Agreement
130,000

 
95,000

Proceeds from issuance of common stock
181,875

 
—

Cost to issue equity
(504
)
 
—

Proceeds from stock options exercised
6

 
—

Taxes paid related to net share settlement of stock-based compensation
(285
)
 
(1
)
Net cash provided by financing activities
131,092

 
94,999

Increase in cash
8,348

 
3,010

Cash at beginning of period
6,287

 
2,095

Cash at end of period
$
14,635

 
$
5,105

 
 
 
 
Supplemental disclosures of cash flow information (Note 11)


 



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 (“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 Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. The Company also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, the Company has a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where it is testing the Meade Peak shale.
On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011 and in connection with Matador’s initial public offering, the former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.
MRC Energy Company holds the primary assets of the Company and has four wholly-owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in Southeast New Mexico and West Texas. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP, which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations, transports limited quantities of third-party natural gas and disposes of limited quantities of third-party salt water.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates
The unaudited condensed consolidated financial statements of Matador and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) but do not include all of the information and footnotes required by generally accepted accounting principles in the United States of America (“U.S. GAAP”) for complete financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC (the “Annual Report”). 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 June 30, 2014, consolidated results of operations for the three and six months ended June 30, 2014 and 2013, consolidated changes in shareholders’ equity for the six months ended June 30, 2014 and consolidated cash flows for the six months ended June 30, 2014 and 2013. Amounts as of December 31, 2013 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 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

7
Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED - CONTINUED

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
 Property and Equipment
The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method 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 $0.7 million of its general and administrative costs for the three months ended June 30, 2014 and 2013, respectively. The Company capitalized approximately $0.7 million and $0.5 million of its interest expense for the three months ended June 30, 2014 and 2013, respectively. The Company capitalized approximately $2.8 million and $1.4 million of its general and administrative costs for the six months ended June 30, 2014 and 2013, respectively. The Company capitalized approximately $1.4 million and $0.8 million of its interest expense for the six months ended June 30, 2014 and 2013, 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 dictate that a 10% discount factor be used. For the period from July 2013 through June 2014, these average oil and natural gas prices were $96.75 per barrel (“Bbl”) and $4.104 per million British thermal units (“MMBtu”), respectively. For the period from July 2012 through June 2013, these average oil and natural gas prices were $88.13 per Bbl and $3.444 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 June 30, 2014 and 2013, the Company’s oil and natural gas reserves estimates were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at June 30, 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 June 30, 2014. Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at June 30, 2013, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs for the three months ended June 30, 2013. At March 31, 2013, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $13.7 million. The Company recorded an impairment charge of $21.2 million to its net capitalized costs and a deferred income tax credit of $7.5 million related to the full-cost ceiling limitation at March 31, 2013. These charges are reflected in the Company’s unaudited condensed consolidated statement of operations for the six months ended June 30, 2013. At June 30, 2013, the Company retained a full valuation allowance against its deferred tax assets, and as a result, the Company recorded no deferred income tax provision in its unaudited condensed consolidated statement of operations for the three and six months ended June 30, 2013.
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.
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 and six months ended June 30, 2014 and 2013 (in thousands).
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
2014
 
2013
 
2014
 
2013
Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
68,531

 
55,839

 
67,108

 
55,729

Dilutive effect of options and restricted stock units
689

 
98

 
663

 
90

Diluted weighted average common shares outstanding
69,220

 
55,937

 
67,771

 
55,819

Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows Financial Accounting Standards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value.
Recent Accounting Pronouncements
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

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

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.
NOTE 3 - COMMON STOCK
On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million, the Company received net proceeds of approximately $181.3 million. The Company used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under its Credit Agreement (see Note 5), which amounts may be reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements.
NOTE 4 - ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2014 (in thousands).
 
 
Beginning asset retirement obligations
$
7,484

Liabilities incurred during period
838

Liabilities settled during period
(22
)
Revisions in estimated cash flows
1,659

Accretion expense
241

Ending asset retirement obligations
10,200

Less: current asset retirement obligations(1)
(477
)
Long-term asset retirement obligations
$
9,723

 _______________
(1)
Included in accrued liabilities in the Company’s unaudited condensed consolidated balance sheet at June 30, 2014.
NOTE 5 - REVOLVING CREDIT AGREEMENT
On September 28, 2012, the Company amended and restated its revolving credit agreement. This third amended and restated credit agreement (the “Credit Agreement”) 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. Borrowings are secured by mortgages on substantially all of the Company’s proved oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, 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 the 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 first quarter of 2014, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at December 31, 2013, and as a result, on March 12, 2014, the borrowing base under the Credit Agreement was increased to $385.0 million, and the conforming borrowing base was increased to $310.0 million. At that time, the Company amended the Credit Agreement to, among other things, provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million. The Credit Agreement was also amended to eliminate the current ratio covenant and to increase the debt to EBITDA ratio covenant, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, to 4.25 or less. Furthermore, the interest rate charged to the Company based on its outstanding level of borrowings was reduced by 0.25% across the borrowing

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

NOTE 5 - REVOLVING CREDIT AGREEMENT - Continued

grid as a result of this amendment. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. The Company may request one additional unscheduled redetermination of its borrowing base prior to the next scheduled redetermination. The Company expects additional increases to the borrowing base primarily as a result of anticipated increases in its proved oil and natural gas reserves, and particularly its proved developed oil and natural gas reserves.
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 $2.0 million at June 30, 2014, 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 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.
On May 29, 2014, using a portion of the net proceeds from its public equity offering, the Company repaid $180.0 million of its outstanding borrowings under the Credit Agreement. At June 30, 2014, the Company had $150.0 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 June 30, 2014, the Company’s outstanding borrowings bore interest at an effective interest rate of approximately 3.6% per annum. From July 1, 2014 through August 6, 2014, the Company borrowed an additional $45.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures and the acquisition of additional leasehold interests. At August 6, 2014, the Company had $195.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement.
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 on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate 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; and
•
engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets.

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

NOTE 5 - REVOLVING CREDIT AGREEMENT - Continued

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:
•
failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other 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.
During the second quarter of 2014, Bank of America, N.A. replaced Citibank, N.A. as a lender under the Credit Agreement. At June 30, 2014, the Company believes that it was in compliance with the terms of the Credit Agreement.
NOTE 6 - INCOME TAXES
The Company had an effective tax rate of 36.9% and 36.8% for the three and six months ended June 30, 2014, respectively. Total income tax expense for the three and six months ended June 30, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and taxable income. Based upon its projections for the remainder of 2014 and 2013, the Company anticipated incurring a small alternative minimum tax (“AMT”) liability for the years ending December 31, 2014 and 2013, the proportionate shares of which were recorded as the current income tax provision for the three and six months ended June 30, 2014 and 2013. The Company established a valuation allowance at September 30, 2012 and retained a full valuation allowance of approximately $6.7 million at June 30, 2013 due to uncertainties regarding the future realization of its net deferred tax assets. As a result, there was no income tax expense or benefit recorded for the three and six months ended June 30, 2013, other than the AMT liability noted above.
NOTE 7 - STOCK-BASED COMPENSATION
In February and March 2014, the Company granted awards of options to certain of its employees to purchase 49,721 shares of the Company’s common stock at an exercise price of $19.71, 224,962 shares at an exercise price of $23.40 and 75,247 shares at an exercise price of $22.66. The fair value of these awards was approximately $3.3 million. The Company also granted awards of 150,854 shares of restricted stock to certain of its employees in February and March 2014. The fair value of these restricted stock awards was approximately $3.4 million. All of these awards vest over a term of three or four years.
NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS
From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, 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 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, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof) were the counterparties for the Company’s commodity derivatives at June 30, 2014. 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

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

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 June 30, 2014, 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 2014 and 2015.
At June 30, 2014, 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 2014 and 2015.

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

NOTE 8 - 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 June 30, 2014.
Commodity
Calculation Period
 
Notional
Quantity
(Bbl/month)
 
Price
Floor
($/Bbl)
 
Price
Ceiling
($/Bbl)
 
Fair Value of
Asset
(Liability)
(thousands)
Oil
07/01/2014 - 12/31/2014
 
10,000

 
85.00

 
100.55

 
$
(260
)
Oil
07/01/2014 - 12/31/2014
 
12,200

 
85.00

 
100.40

 
(326
)
Oil
07/01/2014 - 12/31/2014
 
15,000

 
85.00

 
97.50

 
(598
)
Oil
07/01/2014 - 12/31/2014
 
30,000

 
85.00

 
98.00

 
(1,122
)
Oil
07/01/2014 - 12/31/2014
 
12,000

 
85.00

 
100.00

 
(340
)
Oil
07/01/2014 - 12/31/2014
 
15,000

 
87.00

 
97.00

 
(630
)
Oil
07/01/2014 - 12/31/2014
 
20,000

 
88.00

 
95.60

 
(979
)
Oil
07/01/2014 - 12/31/2014
 
20,000

 
90.00

 
97.00

 
(825
)
Oil
07/01/2014 - 12/31/2014
 
12,000

 
90.00

 
97.90

 
(443
)
Oil
07/01/2014 - 12/31/2014
 
15,000

 
90.00

 
97.90

 
(553
)
Oil
07/01/2014 - 12/31/2014
 
15,000

 
90.00

 
98.00

 
(546
)
Oil
07/01/2014 - 12/31/2014
 
15,000

 
90.00

 
101.15

 
(337
)
Oil
07/01/2014 - 12/31/2014
 
10,000

 
90.00

 
103.75

 
(133
)
Oil
07/01/2014 - 12/31/2014
 
10,000

 
90.00

 
103.88

 
(130
)
Oil
07/01/2014 - 12/31/2014
 
10,000

 
90.00

 
104.15

 
(122
)
Oil
01/01/2015 - 12/31/2015
 
20,000

 
80.00

 
100.00

 
(714
)
Oil
01/01/2015 - 12/31/2015
 
20,000

 
80.00

 
101.00

 
(610
)
Oil
01/01/2015 - 12/31/2015
 
20,000

 
85.00

 
99.00

 
(624
)
Oil
01/01/2015 - 12/31/2015
 
20,000

 
85.00

 
100.00

 
(550
)
Oil
01/01/2015 - 12/31/2015
 
20,000

 
85.00

 
105.10

 
(105
)
Total open oil costless collar contracts
 
 
 
 
 
 
 
(9,947
)

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

Commodity
Calculation Period
 
Notional
Quantity
(MMBtu/month)
 
Price
Floor
($/MMBtu)
 
Price
Ceiling
($/MMBtu)
 
Fair Value of
Asset
(Liability)
(thousands)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.00

 
5.15

 
(36
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.21

 
(32
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.22

 
(32
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.37

 
(23
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.42

 
(21
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.50

 
4.90

 
(49
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.75

 
4.75

 
(53
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
3.75

 
4.77

 
(53
)
Natural Gas
07/01/2014 - 12/31/2014
 
100,000

 
4.00

 
4.60

 
(58
)
Natural Gas
07/01/2014 - 12/31/2015
 
100,000

 
3.75

 
4.36

 
(310
)
Natural Gas
07/01/2014 - 12/31/2015
 
100,000

 
3.75

 
4.45

 
(241
)
Natural Gas
01/01/2015 - 03/31/2015
 
200,000

 
4.00

 
4.84

 
(81
)
Natural Gas
01/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.60

 
(79
)
Natural Gas
01/01/2015 - 12/31/2015
 
100,000

 
3.75

 
4.65

 
(70
)
Natural Gas
01/01/2015 - 12/31/2015
 
200,000

 
3.75

 
5.04

 
47

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

 
3.75

 
5.34

 
75

Total open natural gas costless collar contracts
 
 
 
 
 
 
 
(1,016
)
Commodity
Calculation Period
 
Notional Quantity
(Gal/month)
 
Fixed Price
($/Gal)
 
Fair Value of Asset (Liability)
(thousands)
Propane
07/01/2014 - 12/31/2014
 
116,000

 
0.950

 
(81
)
Propane
07/01/2014 - 12/31/2014
 
116,000

 
1.003

 
(48
)
Propane
07/01/2014 - 12/31/2014
 
60,000

 
1.015

 
(20
)
Propane
07/01/2014 - 12/31/2014
 
84,000

 
1.143

 
36

Propane
07/01/2014 - 12/31/2014
 
68,000

 
1.150

 
32

Propane
01/01/2015 - 12/31/2015
 
150,000

 
1.000

 
(121
)
Propane
01/01/2015 - 12/31/2015
 
100,000

 
1.030

 
(45
)
Propane
01/01/2015 - 12/31/2015
 
68,000

 
1.073

 
3

Normal Butane
07/01/2014 - 12/31/2014
 
17,500

 
1.540

 
24

Normal Butane
07/01/2014 - 12/31/2014
 
45,500

 
1.550

 
66

Isobutane
07/01/2014 - 12/31/2014
 
22,000

 
1.640

 
38

Isobutane
07/01/2014 - 12/31/2014
 
37,000

 
1.640

 
66

Natural Gasoline
07/01/2014 - 12/31/2014
 
30,000

 
1.970

 
(37
)
Natural Gasoline
07/01/2014 - 12/31/2014
 
41,000

 
2.000

 
(46
)
   Total open NGL swap contracts
 
 
 
 
 
 
(133
)
Total open derivative financial instruments
 
 
 
 
 
 
$
(11,096
)
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, D and E 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.

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

 The following table presents the gross asset 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 June 30, 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
$
200

 
$
(200
)
 
$
—

 
$
—

   Other assets
306

 
(306
)
 
—

 
—

Counterparty B

 

 

 
 
   Current assets
482

 
(482
)
 
—

 
—

   Other assets
551

 
(468
)
 
83

 
83

Counterparty C

 

 

 
 
   Current assets
946

 
(946
)
 
—

 
—

   Other assets
889

 
(889
)
 
—

 
—

Counterparty D
 
 
 
 
 
 
 
   Current assets
15

 
(15
)
 
—

 
—

   Other assets
—

 
—

 
—

 
—

Counterparty E
 
 
 
 
 
 
 
   Current assets
254

 
(232
)
 
22

 
—

   Other assets
416

 
(328
)
 
88

 
—

Total
$
4,059

 
$
(3,866
)
 
$
193

 
$
83


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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table presents the gross 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 June 30, 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
$
3,078

 
$
(200
)
 
$
2,878

 
$
—

   Other liabilities
473

 
(306
)
 
167

 
—

Counterparty B

 

 

 

   Current liabilities
2,761

 
(482
)
 
2,279

 
83

   Other liabilities
692

 
(468
)
 
224

 
—

Counterparty C

 

 

 

   Current liabilities
5,738

 
(946
)
 
4,792

 
—

   Other liabilities
1,523

 
(889
)
 
634

 
—

Counterparty D
 
 
 
 
 
 
 
   Current liabilities
68

 
(15
)
 
53

 
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty E
 
 
 
 
 
 
 
   Current liabilities
494

 
(232
)
 
262

 
—

   Other liabilities
328

 
(328
)
 
—

 
—

Total
$
15,155

 
$
(3,866
)
 
$
11,289

 
$
83

 

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table presents the gross asset 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, 2013 (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
$
1,746

 
$
(1,746
)
 
$
—

 
$
—

   Other assets
—

 
—

 
—

 
—

Counterparty B
 
 
 
 
 
 
 
   Current assets
1,371

 
(1,371
)
 
—

 
—

   Other assets
841

 
(668
)
 
173

 
—

Counterparty C
 
 
 
 
 
 
 
   Current assets
2,886

 
(2,873
)
 
13

 
—

   Other assets
1,046

 
(1,046
)
 
—

 
—

Counterparty D
 
 
 
 
 
 
 
Current assets
6

 
—

 
6

 
—

Other assets
—

 
—

 
—

 
—

Total
$
7,896

 
$
(7,704
)
 
$
192

 
$
—

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, 2013 (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
$
2,550

 
$
(1,746
)
 
$
804

 
$
—

   Other liabilities
—

 
—

 
—

 
—

Counterparty B

 

 

 
 
   Current liabilities
2,136

 
(1,371
)
 
765

 
—

   Other liabilities
668

 
(668
)
 
—

 
—

Counterparty C
 
 
 
 
 
 
 
   Current liabilities
3,996

 
(2,873
)
 
1,123

 
—

   Other liabilities
1,299

 
(1,046
)
 
253

 
—

Counterparty D
 
 
 
 
 
 
 
   Current liabilities
—

 
—

 
—

 
—

   Other liabilities
—

 
—

 
—

 
—

Total
$
10,649

 
$
(7,704
)
 
$
2,945

 
$
—


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

NOTE 8 - 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 
 June 30,
 
Six Months Ended 
 June 30,
Type of Instrument
Location in Condensed Consolidated Statement of Operations
 
2014
 
2013
 
2014
 
2013
Derivative Instrument
 
 
 
 
 
 
 
 
 
Oil
Revenues: Realized loss on derivatives
 
$
(2,764
)
 
$
(228
)
 
$
(3,706
)
 
$
(465
)
Natural Gas
Revenues: Realized (loss) gain on derivatives
 
(187
)
 
105

 
(776
)
 
629

NGL
Revenues: Realized gain (loss) on derivatives
 
38

 
377

 
(274
)
 
482

Realized (loss) gain on derivatives
 
(2,913
)
 
254

 
(4,756
)
 
646

Oil
Revenues: Unrealized (loss) gain on derivatives
 
(5,701
)
 
4,042

 
(7,751
)
 
1,314

Natural Gas
Revenues: Unrealized gain (loss) on derivatives
 
698

 
2,323

 
(569
)
 
(189
)
NGL
Revenues: Unrealized (loss) gain on derivatives
 
(231
)
 
1,161

 
(22
)
 
1,576

Unrealized (loss) gain on derivatives
 
(5,234
)
 
7,526

 
(8,342
)
 
2,701

Total
 
 
$
(8,147
)
 
$
7,780

 
$
(13,098
)
 
$
3,347

NOTE 9 - FAIR VALUE MEASUREMENTS
The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.
Level 1
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued 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 June 30, 2014 and December 31, 2013, the carrying values reported on the unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities.
At June 30, 2014 and December 31, 2013, 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.

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

NOTE 9 - FAIR VALUE MEASUREMENTS - Continued

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2014 and December 31, 2013 (in thousands). 
 
Fair Value Measurements at
June 30, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Oil, natural gas and NGL derivatives
$
—

 
$
193

 
$
—

 
$
193

Oil, natural gas and NGL derivatives
—

 
(11,289
)
 
—

 
(11,289
)
Total
$
—

 
$
(11,096
)
 
$
—

 
$
(11,096
)
 
Fair Value Measurements at
December 31, 2013 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
   Oil, natural gas and NGL derivatives
$
—

 
$
192

 
$
—

 
$
192

   Oil, natural gas and NGL derivatives
—

 
(2,945
)
 
—

 
(2,945
)
           Total
$
—

 
$
(2,753
)
 
$
—

 
$
(2,753
)
Additional disclosures related to derivative financial instruments are provided in Note 8. 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 June 30, 2014 and December 31, 2013 (in thousands).
  
Fair Value Measurements at
June 30, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$
—

 
$
—

 
$
(2,497
)
 
$
(2,497
)
Total
$
—

 
$
—

 
$
(2,497
)
 
$
(2,497
)
 
Fair Value Measurements at
December 31, 2013 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$
—

 
$
—

 
$
(1,470
)
 
$
(1,470
)
Total
$
—

 
$
—

 
$
(1,470
)
 
$
(1,470
)
No impairment to any equipment was recorded during the three months ended June 30, 2014 and December 31, 2013.

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

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Natural Gas and NGL Processing and Transportation Commitments
Effective September 1, 2012, the Company entered into a firm five-year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period.
Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company’s remaining aggregate undiscounted minimum commitments under this agreement are $8.0 million at June 30, 2014. The Company paid $1.7 million and $1.0 million in processing and transportation fees under this agreement during the three months ended June 30, 2014 and 2013, respectively, and $2.8 million and $1.8 million during the six months ended June 30, 2014 and 2013, 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 are 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 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 $54.7 million at June 30, 2014.
At June 30, 2014, 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 $30.3 million at June 30, 2014, which it expects to incur within the next few months.
From time to time, the Company enters into contracts with third parties for geological and geophysical data on certain prospects to assist in the exploration of these prospects. The undiscounted minimum commitments under these agreements totaled approximately $4.1 million at June 30, 2014, 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 position, results of operations or cash flows.

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

NOTE 11 - SUPPLEMENTAL DISCLOSURES


Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at June 30, 2014 and December 31, 2013 (in thousands).
 
June 30, 
 2014
 
December 31,
2013
Accrued evaluated and unproved and unevaluated property costs
$
86,066

 
$
52,605

Accrued support equipment and facilities costs
293

 
—

Accrued cost to issue equity
87

 
—

Accrued stock-based compensation
109

 
56

Accrued lease operating expenses
8,751

 
6,251

Accrued interest on borrowings under Credit Agreement
95

 
141

Accrued asset retirement obligations
477

 
175

Accrued partners’ share of joint interest charges
4,109

 
1,173

Other
5,142

 
3,586

Total accrued liabilities
$
105,129

 
$
63,987

Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2014 and 2013 (in thousands).
 
Six Months Ended 
 June 30,
 
2014
 
2013
Cash paid for interest expense, net of amounts capitalized
$
3,058

 
$
1,817

Asset retirement obligations related to mineral properties
2,343

 
751

Asset retirement obligations related to support equipment and facilities
132

 
4

Increase (decrease) in liabilities for oil and natural gas properties capital expenditures
34,444

 
(6,859
)
Increase (decrease) in liabilities for support equipment and facilities
293

 
(914
)
Increase in liabilities for accrued cost to issue equity
86

 
—

Issuance of restricted stock units for Board and advisor services
197

 
87

Issuance of common stock for advisor services
10

 
17

Stock-based compensation expense recognized as liability
1,200

 
284

Transfer of inventory from oil and natural gas properties
133

 
191

NOTE 12 - 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. The subsidiaries of Matador (the “Subsidiaries”) are co-registrants with Matador on each Form S-3, and the registration statements register guarantees of debt securities by the Subsidiaries. As of June 30, 2014, the Subsidiaries are 100% owned by Matador and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). Matador has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to Matador. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by Matador, such guarantees will constitute joint and several obligations.
 

22

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, 2013 (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 in conjunction with “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (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: 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;

23

•
government regulation and taxation of the oil and natural gas industry;
•
our marketing of oil and natural gas;
•
our exploitation projects or property acquisitions;
•
our costs of exploiting and developing our properties and conducting other operations;
•
general economic conditions;
•
competition in the oil and natural gas industry;
•
the effectiveness of our risk management and hedging activities;
•
environmental liabilities;
•
counterparty credit risk;
•
developments in oil-producing and natural gas-producing countries;
•
our future operating results;
•
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 Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, we have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale.
Second Quarter and Year-to-Date Highlights
Our total oil equivalent production for the second quarter of 2014 was 1.4 million BOE. Our average daily oil equivalent production for the second quarter of 2014 was 15,424 BOE per day, of which 8,809 Bbl per day, or 57%, was oil and 39.7 MMcf per day, or 43%, was natural gas. These quarterly production results were the best in our Company’s history. Our total oil production for the second quarter of 2014 of 802,000 Bbl and our average daily oil production of 8,809 Bbl per day were also record quarterly results. We achieved these results despite having as much as 10% to 15% of our total production capacity shut in or restricted at various times during the second quarter while offsetting wells were drilled and completed and pipeline connections were being made. For the six months ended June 30, 2014, our total oil equivalent production was 2.5 million BOE, averaging 13,673 BOE per day, and our total oil production was 1.5 million Bbl, averaging 8,080 Bbl per day. These results were also the best reported for any six-month period in our Company’s history.

24

During the second quarter of 2014, our oil and natural gas revenues were $99.1 million, an increase of 70% from oil and natural gas revenues of $58.2 million during the second quarter of 2013. This increase was primarily attributable to the 79% increase in our oil production to 802,000 Bbl in the second quarter of 2014, as compared to 447,000 Bbl produced in the second quarter of 2013. This increase in oil production is due primarily to our drilling operations in the Eagle Ford shale as well as initial production contributions from newly drilled wells in the Permian Basin. For the six months ended June 30, 2014, our oil and natural gas revenues were $178.0 million, an increase of 51% from oil and natural gas revenues of $117.5 million in the first six months of 2013. For the three months ended June 30, 2014, our Adjusted EBITDA was $69.5 million, an increase of 70% from Adjusted EBITDA of $40.8 million during the three months ended June 30, 2013. For the six months ended June 30, 2014, our Adjusted EBITDA was $125.8 million, an increase of 54% from $81.4 million during the six months ended June 30, 2013. These oil and natural gas revenues and Adjusted EBITDA values were the best reported for any three-month and six-month period, respectively, in our Company’s history. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for 2014, see “— Results of Operations” below.
On May 29, 2014, we completed an underwritten public offering of 7,500,000 shares of our common stock and received net proceeds of approximately $181.3 million. We have used the net proceeds from this offering to fund a portion of our capital expenditures, including to operate a fourth rig in the Permian Basin throughout the remainder of 2014, allowing us to operate two drilling rigs for the development of our acreage in the Eagle Ford shale and two rigs for the exploration and delineation of our acreage in the Wolfcamp and Bone Spring plays in the Permian Basin. We also have used and expect to continue to use portions of the net proceeds from the equity offering to fund targeted acquisitions of additional acreage in the Permian Basin, as well as in the Eagle Ford shale and the Haynesville shale, for our participation in additional Haynesville wells proposed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) and for other general working capital needs. Pending such uses, we repaid $180.0 million in outstanding borrowings under our third amended and restated credit agreement (the “Credit Agreement”) in May 2014, which amounts may be re-borrowed in accordance with the terms of that facility.
Our 2014 drilling activity will continue to be focused on increasing our oil production and reserves in South Texas, primarily in the Eagle Ford shale play, while we expand our exploration and delineation efforts in the Permian Basin in Southeast New Mexico and West Texas. At March 31, 2014, we had two contracted drilling rigs operating on our Eagle Ford acreage in South Texas and one contracted drilling rig operating in the Permian Basin. In April 2014, we replaced the drilling rig operating in the central portion of our Eagle Ford acreage in Karnes County with a new “walking” rig. Due to a temporary contract overlap resulting from initiating drilling operations with this second “walking” rig, we moved the rig being replaced in Karnes County to Loving County, Texas in order to provide us with a second rig in the Permian Basin. As noted above, we are using a portion of the proceeds from our May 2014 equity offering to, among other items, keep this fourth rig operating full-time in the Permian Basin throughout 2014. As a result, as of August 6, 2014, we were operating four contracted drilling rigs — two in the Eagle Ford and two in the Permian Basin. Because of the timing of the addition of this fourth drilling rig in the Permian Basin and our projected drilling and completions schedule, we do not expect this rig to materially impact our anticipated 2014 oil and natural gas production or our anticipated 2014 oil and natural gas revenues. Rather, we anticipate that the addition of this second rig in the Permian Basin will start to have a material impact on our operations and financial results beginning in 2015. In addition, we have decided to further accelerate our Permian drilling program by adding at least one additional rig at the beginning of 2015.
In addition, during the first quarter of 2014, we were notified by Chesapeake of its intent to drill up to a total of 30 gross (6.3 net) Haynesville wells on our Elm Grove acreage in southern Caddo Parish, Louisiana during 2014. We retain the right to participate for up to a 25% working interest in all wells drilled on this property with our working interest proportionately reduced to our leasehold position in any individual drilling unit. Chesapeake began actively drilling on these properties during the second quarter of 2014 and, at August 6, 2014, was operating four drilling rigs on these properties. These wells are being drilled and completed in a multi-well batch mode, and as a result, we do not expect to see significant contributions from these wells to our natural gas production until late in the third quarter and perhaps even into the fourth quarter of 2014. At August 6, 2014, we had agreed to participate in 21 gross (4.4 net) wells in progress or proposed on this acreage, with an estimated total capital commitment of $37.4 million. Of these wells, 19 gross (4.2 net) wells are currently anticipated to be completed and placed on production prior to the end of the year, with most coming on line in the fourth quarter of 2014. Should Chesapeake elect to drill all 30 gross wells on this acreage in 2014, our working interest would be equivalent to approximately 6.3 net wells at an estimated capital expenditure of approximately $50.0 million.
As a result of our determination to operate two drilling rigs in the Permian Basin for the remainder of 2014, the ongoing and anticipated Chesapeake drilling activity in the Haynesville shale and additional leasehold and seismic data acquisitions anticipated throughout the remainder of 2014, we increased our 2014 capital expenditure budget from $440.0 million to $570.0 million during the second quarter of 2014. At June 30, 2014, we had incurred $273.3 million, or approximately 48%, of this anticipated 2014 capital expenditure budget.

25

We had two contracted drilling rigs operating in the Permian Basin during the majority of the second quarter of 2014 — one in Loving County, Texas and the other in Lea County, New Mexico. Due to the timing of our drilling, completion and production operations, we did not complete and place on production any new Permian Basin wells during the second quarter. However, three new Permian wells were completed and began testing in mid-to-late July — the Norton Schaub #1H well in Loving County, Texas and the Pickard State 20-18-34 #1H and the Pickard State 20-18-34 #2H wells in Lea County, New Mexico. The Norton Schaub #1H well flowed 1,026 BOE per day, including 706 Bbl of oil per day and 1,922 Mcf of natural gas per day (69% oil), at 3,000 pounds per square inch (“psi”) flowing surface pressure on a 22/64th inch choke during its 24-hour initial potential test in mid-July 2014. This well was completed in the upper portion of the Wolfcamp formation, the Wolfcamp “A,” at approximately 10,800 feet true vertical depth. We drilled a 4,700-ft horizontal lateral in the Norton Schaub #1H and stimulated this well with 20 hydraulic fracturing stages, including approximately 200,000 Bbl of fluid and 9.8 million pounds of sand. This is our second successful test of the Wolfcamp “A” formation in our Wolf prospect area. The Norton Schaub #1H was drilled in our Wolf prospect in Loving County near and to the northwest of our original well on this prospect, the Dorothy White #1H. The Dorothy White #1H was also completed in the Wolfcamp “A” formation and has continued to exhibit strong performance since being placed on production in January 2014. At July 30, 2014, in approximately seven months on production, including its initial cleanup phase, the Dorothy White #1H well has produced 175,000 BOE, including almost 115,000 Bbl of oil (66% oil). Based on the success of these two initial wells, we intend to operate one of the two Permian Basin drilling rigs full time in the Loving County area throughout the remainder of 2014.
In the Ranger prospect area, the Pickard State 20-18-34 #1H (Second Bone Spring test) and Pickard State 20-18-34 #2H (Wolfcamp “D” test) were drilled from a single surface pad and then completed back-to-back, with the Pickard State 20-18-34 #1H being put on production first after completion. The Pickard 20-18-34 #1H was completed in the Second Bone Spring sand at approximately 9,900 feet true vertical depth. We drilled a 4,100-ft horizontal lateral in the Pickard State 20-18-34 #1H and stimulated this well with 17 hydraulic fracturing stages, including approximately 167,000 Bbl of fluid and 7.3 million pounds of sand. This well flowed 592 BOE per day, including 535 Bbl of oil per day and 340 Mcf of natural gas per day (90% oil) at 750 psi flowing surface pressure on a 22/64th inch choke during its 24-hour initial potential test in late July 2014. The Pickard State 20-18-34 #1H is our second positive test of the Second Bone Spring sand in the Ranger prospect area, and early indications are that this well may be comparable to or better than our initial Second Bone Spring well, the Ranger 33 State Com #1H, which had produced 123,000 BOE, including 113,000 Bbl of oil (91% oil), in about nine months on production at July 30, 2014. The Pickard State 20-18-34 #1H well flowed oil at higher rates and at higher flowing pressures on a comparable choke than the Ranger 33 State Com #1H. At August 6, 2014, the Pickard 20-18-34 #2H well, a Wolfcamp “D” test in the Ranger prospect area, was still in the flowback period following its completion operations. At that date, the well was flowing oil and natural gas (85% to 90% oil), but has yet to have its initial potential test.
We also had two drilling rigs operating in South Texas during the second quarter of 2014 as we continued to develop our Eagle Ford acreage. During the second quarter of 2014, we completed and began producing oil and natural gas from six gross (5.4 net) operated and three gross (0.8 net) non-operated Eagle Ford shale wells. We completed three operated Eagle Ford wells on our Northcut lease and two wells on our Martin Ranch lease in La Salle County and one well on our Lyssy lease in southern Wilson County. The three non-operated wells were completed on our Troutt lease in La Salle County. The Northcut wells began producing in mid-April, the Martin Ranch wells began producing in mid-May and the Lyssy well began producing in mid-June. As a result, these six wells did not contribute fully to our production volumes for the second quarter of 2014 or for the first half of 2014. We also participated in 13 gross (0.6 net) non-operated Haynesville shale wells completed and placed on production during the second quarter of 2014, but these wells did not include any of the 30 gross wells in progress or proposed by Chesapeake on our Elm Grove properties as described above.
At June 30, 2014, our estimated total proved oil and natural gas reserves were 57.2 million BOE, including 18.6 million Bbl of oil and 231.4 Bcf of natural gas, with a PV-10 of $826.0 million and a Standardized Measure of $723.0 million. At December 31, 2013, our estimated proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, and at June 30, 2013, our estimated proved oil and natural gas reserves were 38.9 million BOE, including 12.1 million Bbl of oil and 160.8 Bcf of natural gas. Our proved oil reserves of 18.6 million Bbl at June 30, 2014 increased 54%, as compared to 12.1 million Bbl at June 30, 2013, and 14%, as compared to 16.4 million Bbl at December 31, 2013. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
We realized a weighted average oil price of $97.92 per Bbl for the three months ended June 30, 2014, as compared to $99.77 per Bbl for the three months ended June 30, 2013. 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 oil price index less transportation costs. We realized a weighted average natural gas price of $5.69 per Mcf for the three months ended June 30, 2014, as compared to $4.38 per Mcf for the three months ended June 30, 2013. This price reflects an uplift as a result of natural gas liquids we produce with our Eagle Ford natural gas production, and we also expect to receive an uplift in the price we receive for most of our natural gas

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production from the Permian Basin due to natural gas liquids. Natural gas prices, excluding any uplift from natural gas liquids, were also considerably higher during the second quarter of 2014 as compared to the second quarter of 2013. 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 received during the second quarter of 2014.
We began 2014 with approximately 70,800 gross (44,800 net) acres in the Permian Basin in Southeast New Mexico and West Texas. Between January 1 and August 6, 2014, we acquired an additional 23,200 gross (17,200 net) acres in this area, primarily in Loving County, Texas and in Lea and Eddy Counties, New Mexico. Including these acreage acquisitions, at August 6, 2014, our total Permian Basin acreage position was approximately 94,000 gross (62,000 net) acres. We have also been actively acquiring additional Eagle Ford acreage in South Texas. Between January 1, 2014 and August 6, 2014, we acquired (or expect to acquire by the middle of August) 3,100 gross (2,900 net) acres in South Texas prospective for the Eagle Ford shale in La Salle, Karnes and southern Atascosa Counties. We plan to continue our leasing and acquisition efforts in the Permian Basin, Eagle Ford shale and Haynesville shale as opportunities are identified.
Estimated Proved Reserves
The following table sets forth our estimated total proved oil and natural gas reserves at June 30, 2014, December 31, 2013 and June 30, 2013. 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 in South Texas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our 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.
 
June 30,
2014
 
December 31,
2013
 
June 30,
2013
Estimated Proved Reserves Data: (1) (2)
 
 
 
 
 
Estimated proved reserves:
 
 
 
 
 
Oil (MBbl)(3)
18,627

 
16,362

 
12,128

Natural Gas (Bcf)(4)
231.4

 
212.2

 
160.8

Total (MBOE)(5)
57,202

 
51,729

 
38,931

Estimated proved developed reserves:
 
 
 
 
 
Oil (MBbl)(3)
9,917

 
8,258

 
6,591

Natural Gas (Bcf)(4)
60.0

 
53.5

 
57.8

Total (MBOE)(5)
19,917

 
17,168

 
16,221

Percent developed
34.8
%
 
33.2
%
 
41.7
%
Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MBbl)(3)
8,711

 
8,104

 
5,537

Natural Gas (Bcf)(4)
171.4

 
158.7

 
103.0

Total (MBOE)(5)
37,285

 
34,561

 
22,710

PV-10(6) (in millions)
$
826.0

 
$
655.2

 
$
522.3

Standardized Measure(7) (in millions)
$
723.0

 
$
578.7

 
$
477.6

_______________
(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

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prices for the period from July 2013 through June 2014 were $96.75 per Bbl for oil and $4.104 per MMBtu for natural gas, for the period from January 2013 through December 2013 were $93.42 per Bbl for oil and $3.670 per MMBtu for natural gas and for the period from July 2012 through June 2013 were $88.13 per Bbl for oil and $3.444 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 June 30, 2014, December 31, 2013 and June 30, 2013 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 June 30, 2014, December 31, 2013 and June 30, 2013 were, in millions, $103.0, $76.5 and $44.7, 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.
At June 30, 2014, our estimated total proved oil and natural gas reserves were 57.2 million BOE, including 18.6 million Bbl of oil and 231.4 Bcf of natural gas, with a PV-10 of $826.0 million and a Standardized Measure of $723.0 million. At December 31, 2013, our estimated proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, and at June 30, 2013, our estimated proved oil and natural gas reserves were 38.9 million BOE, including 12.1 million Bbl of oil and 160.8 Bcf of natural gas. Our proved oil reserves of 18.6 million Bbl at June 30, 2014 increased 14%, as compared to 16.4 million Bbl at December 31, 2013, and 54%, as compared to 12.1 million Bbl at June 30, 2013. During the six months ended June 30, 2014, our proved developed reserves increased 16% from 17.2 million BOE at December 31, 2013 to 19.9 million BOE at June 30, 2014. Year-over-year, our proved developed reserves increased 23% from 16.2 million BOE at June 30, 2013. At June 30, 2014, approximately 35% of our total proved reserves were proved developed reserves, 33% of our total proved reserves were oil and 67% 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
There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.
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.

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Results of Operations
Revenues
The following table summarizes our revenues and production data for the periods indicated:
 
Three Months Ended 
 June 30,