10-Q 1 mtdr-2014930x10q.htm 10-Q MTDR-2014.9.30-10Q

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 September 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 November 4, 2014, there were 73,362,360 shares of the registrant’s common stock, par value $0.01 per share, outstanding.



MATADOR RESOURCES COMPANY
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 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)
 
September 30,
2014
 
December 31,
2013
ASSETS
 
 
 
Current assets
 
 
 
Cash
$
7,723

 
$
6,287

Accounts receivable
 
 
 
Oil and natural gas revenues
33,440

 
25,823

Joint interest billings
9,322

 
4,785

Other
1,517

 
1,066

Derivative instruments
3,929

 
19

Deferred income taxes

 
1,636

Lease and well equipment inventory
1,278

 
785

Prepaid expenses
1,846

 
1,771

Total current assets
59,055

 
42,172

Property and equipment, at cost
 
 
 
Oil and natural gas properties, full-cost method
 
 
 
Evaluated
1,469,633

 
1,090,656

Unproved and unevaluated
269,049

 
194,306

Other property and equipment
35,435

 
29,910

Less accumulated depletion, depreciation and amortization
(559,965
)
 
(468,995
)
Net property and equipment
1,214,152

 
845,877

Other assets
 
 
 
Derivative instruments
1,278

 
173

Other assets
2,918

 
2,108

Total other assets
4,196

 
2,281

Total assets
$
1,277,403

 
$
890,330

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
15,420

 
$
25,358

Accrued liabilities
119,361

 
63,987

Royalties payable
13,973

 
7,798

Derivative instruments

 
2,692

Deferred income taxes
802

 

Income taxes payable
2,969

 
404

Other current liabilities
95

 
88

Total current liabilities
152,620

 
100,327

Long-term liabilities
 
 
 
Borrowings under Credit Agreement
250,000

 
200,000

Asset retirement obligations
10,751

 
7,309

Derivative instruments
9

 
253

Deferred income taxes
42,508

 
10,929

Other long-term liabilities
3,176

 
2,588

Total long-term liabilities
306,444

 
221,079

Commitments and contingencies (Note 10)


 


Shareholders’ equity
 
 
 
Common stock - $0.01 par value, 80,000,000 shares authorized; 74,683,934 and 66,958,867 shares issued; and 73,348,734 and 65,652,690 shares outstanding, respectively
747

 
670

Additional paid-in capital
734,065

 
548,935

Retained earnings
94,292

 
30,084

Treasury stock, at cost, 1,335,200 and 1,306,177 shares, respectively
(10,765
)
 
(10,765
)
Total shareholders’ equity
818,339

 
568,924

Total liabilities and shareholders’ equity
$
1,277,403

 
$
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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Revenues
 
 
 
 
 
 
 
Oil and natural gas revenues
$
96,617

 
$
81,868

 
$
274,605

 
$
199,367

Realized loss on derivatives
(701
)
 
(1,165
)
 
(5,458
)
 
(519
)
Unrealized gain (loss) on derivatives
16,293

 
(9,327
)
 
7,950

 
(6,626
)
Total revenues
112,209

 
71,376

 
277,097

 
192,222

Expenses
 
 
 
 
 
 
 
Production taxes and marketing
8,617

 
6,559

 
23,739

 
15,107

Lease operating
13,691

 
8,569

 
34,747

 
29,608

Depletion, depreciation and amortization
35,143

 
26,127

 
90,970

 
74,593

Accretion of asset retirement obligations
130

 
86

 
371

 
248

Full-cost ceiling impairment

 

 

 
21,229

General and administrative
8,099

 
5,395

 
23,417

 
14,146

Total expenses
65,680

 
46,736

 
173,244

 
154,931

Operating income
46,529

 
24,640

 
103,853

 
37,291

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

 

 

 
(192
)
Interest expense
(673
)
 
(2,038
)
 
(3,685
)
 
(4,919
)
Interest and other income
267

 
66

 
715

 
181

Total other expense
(406
)
 
(1,972
)
 
(2,970
)
 
(4,930
)
Income before income taxes
46,123

 
22,668

 
100,883

 
32,361

Income tax provision (benefit)
 
 
 
 
 
 
 
Current
(156
)
 
902

 
2,658

 
980

Deferred
16,660

 
1,661

 
34,017

 
1,661

Total income tax provision
16,504

 
2,563

 
36,675

 
2,641

Net income
$
29,619

 
$
20,105

 
$
64,208

 
$
29,720

Earnings per common share:
 
 
 
 

 

Basic
$
0.40

 
$
0.35

 
$
0.93

 
$
0.53

Diluted
$
0.40

 
$
0.35

 
$
0.92

 
$
0.53

Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
73,341

 
58,016

 
69,185

 
55,766

Diluted
74,028

 
58,152

 
69,879

 
55,889


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 Nine Months Ended September 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 and advisors
17

 

 
13

 

 

 

 
13

Stock options expense related to equity-based awards

 

 
1,666

 

 

 

 
1,666

Stock options exercised
2

 

 
6

 

 

 

 
6

Liability-based stock option awards settled

 

 
84

 

 

 

 
84

Restricted stock issued
205

 
2

 
(2
)
 

 

 

 

Restricted stock forfeited

 

 
(18
)
 

 
29

 

 
(18
)
Restricted stock and restricted stock units expense

 

 
2,171

 

 

 

 
2,171

Current period net income

 

 

 
64,208

 

 

 
64,208

Balance at September 30, 2014
74,683

 
$
747

 
$
734,065

 
$
94,292

 
1,335

 
$
(10,765
)
 
$
818,339


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)
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Operating activities
 
 
 
Net income
$
64,208

 
$
29,720

Adjustments to reconcile net income to net cash provided by operating activities
 
 
 
Unrealized (gain) loss on derivatives
(7,950
)
 
6,626

Depletion, depreciation and amortization
90,970

 
74,593

Accretion of asset retirement obligations
371

 
248

Full-cost ceiling impairment

 
21,229

Stock-based compensation expense
4,665

 
2,763

Deferred income tax provision
34,017

 
1,661

Net loss on asset sales and inventory impairment

 
192

Changes in operating assets and liabilities

 

Accounts receivable
(12,605
)
 
(886
)
Lease and well equipment inventory
(193
)
 
198

Prepaid expenses
(74
)
 
(2,148
)
Other assets
(810
)
 
(728
)
Accounts payable, accrued liabilities and other current liabilities
(820
)
 
(10,702
)
Royalties payable
6,175

 
3,812

Advances from joint interest owners

 
(1,505
)
Income taxes payable
2,565

 
980

Other long-term liabilities
(160
)
 
1,139

Net cash provided by operating activities
180,359

 
127,192

Investing activities


 


Oil and natural gas properties capital expenditures
(407,023
)
 
(257,216
)
Expenditures for other property and equipment
(2,906
)
 
(3,058
)
Purchases of certificates of deposit

 
(61
)
Maturities of certificates of deposit

 
251

Net cash used in investing activities
(409,929
)
 
(260,084
)
Financing activities


 


Repayments of borrowings under Credit Agreement
(180,000
)
 
(130,000
)
Borrowings under Credit Agreement
230,000

 
125,000

Proceeds from issuance of common stock
181,875

 
149,069

Cost to issue equity
(590
)
 
(6,933
)
Proceeds from stock options exercised
6

 

Taxes paid related to net share settlement of stock-based compensation
(285
)
 
(9
)
Net cash provided by financing activities
231,006

 
137,127

Increase in cash
1,436

 
4,235

Cash at beginning of period
6,287

 
2,095

Cash at end of period
$
7,723

 
$
6,330

 
 
 
 
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, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the 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.
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 September 30, 2014, consolidated results of operations for the three and nine months ended September 30, 2014 and 2013, consolidated changes in shareholders’ equity for the nine months ended September 30, 2014 and consolidated cash flows for the nine months ended September 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 interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
 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 $1.5 million and $0.9 million of its general and administrative costs for the three months ended September 30, 2014 and 2013, respectively. The Company capitalized approximately $0.8 million and $0.4 million of its interest expense for the three months ended September 30, 2014 and 2013, respectively. The Company capitalized approximately $4.3 million and $2.3 million of its general and administrative

7

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

costs for the nine months ended September 30, 2014 and 2013, respectively. The Company capitalized approximately $2.2 million and $1.2 million of its interest expense for the nine months ended September 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 October 2013 through September 2014, these average oil and natural gas prices were $95.56 per barrel (“Bbl”) and $4.236 per million British thermal units (“MMBtu”), respectively. For the period from October 2012 through September 2013, these average oil and natural gas prices were $91.69 per Bbl and $3.605 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 September 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 September 30, 2014, 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 September 30, 2014. Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at September 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 September 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 nine months ended September 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.

8

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

 Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. 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 nine months ended September 30, 2014 and 2013 (in thousands).
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
2014
 
2013
 
2014
 
2013
Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
73,341

 
58,016

 
69,185

 
55,766

Dilutive effect of options and restricted stock units
687

 
136

 
694

 
123

Diluted weighted average common shares outstanding
74,028

 
58,152

 
69,879

 
55,889

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 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.
On October 31, 2014, Matador’s board of directors canceled all of the shares of treasury stock outstanding as of September 30, 2014. These shares were restored to the status of authorized but unissued shares of the common stock of the Company.

9

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

NOTE 4 - ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the nine months ended September 30, 2014 (in thousands).
 
 
Beginning asset retirement obligations
$
7,484

Liabilities incurred during period
1,906

Liabilities settled during period
(22
)
Revisions in estimated cash flows
1,552

Accretion expense
371

Ending asset retirement obligations
11,291

Less: current asset retirement obligations(1)
(540
)
Long-term asset retirement obligations
$
10,751

 _______________
(1)
Included in accrued liabilities in the Company’s unaudited condensed consolidated balance sheet at September 30, 2014.
NOTE 5 - REVOLVING CREDIT AGREEMENT
On September 28, 2012, the Company entered into a third amended and restated credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million. The Credit Agreement matures December 29, 2016. MRC Energy Company, which is a subsidiary of the Company and directly or indirectly owns the ownership interests in the Company’s other operating subsidiaries, 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 certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company.
The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the 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 grid as a result of this amendment. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. During the third quarter of 2014, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at July 31, 2014, and as a result, on September 5, 2014, the borrowing base under the Credit Agreement was increased to $450.0 million, and the conforming borrowing base was increased to $375.0 million. This September 2014 redetermination constituted the regularly scheduled November 1 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 September 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

10

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

NOTE 5 - REVOLVING CREDIT AGREEMENT - Continued

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 September 30, 2014, the Company had $250.0 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 September 30, 2014, the Company’s outstanding borrowings bore interest at an effective interest rate of approximately 2.9% per annum. From October 1, 2014 through November 5, 2014, the Company borrowed an additional $40.0 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 November 5, 2014, the Company had $290.0 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 (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 3.75% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less.
Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:
incur indebtedness or grant liens on any of the Company’s assets;
enter into commodity hedging agreements;
declare or pay dividends, distributions or redemptions;
merge or consolidate;
make any loans or investments;
engage in transactions with affiliates; and
engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets.
If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:
failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;
failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
bankruptcy or insolvency events involving the Company or its subsidiaries; and

11

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

NOTE 5 - REVOLVING CREDIT AGREEMENT - Continued

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 September 30, 2014, the Company believes that it was in compliance with the terms of the Credit Agreement.
NOTE 6 - INCOME TAXES
The Company had effective tax rates of 35.8% and 36.4% for the three and nine months ended September 30, 2014, respectively. Total income tax expense for the three and nine months ended September 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 nine months ended September 30, 2014 and 2013. The Company had effective tax rates of 11.3% and 8.2% for the three and nine months ended September 30, 2013, respectively. Total income tax expense for the three and nine months ended September 30, 2013 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income due primarily to the reversal of a valuation allowance of approximately $6.7 million on the Company’s federal deferred tax assets at September 30, 2013, and the impact of permanent differences between book and taxable income.
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 September 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 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

12

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

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

 
85.00

 
100.55
 
18

Oil
10/01/2014 - 12/31/2014
 
12,200

 
85.00

 
100.40
 
22

Oil
10/01/2014 - 12/31/2014
 
15,000

 
85.00

 
97.50
 
19

Oil
10/01/2014 - 12/31/2014
 
30,000

 
85.00

 
98.00
 
40

Oil
10/01/2014 - 12/31/2014
 
12,000

 
85.00

 
100.00
 
21

Oil
10/01/2014 - 12/31/2014
 
15,000

 
87.00

 
97.00
 
35

Oil
10/01/2014 - 12/31/2014
 
20,000

 
88.00

 
95.60
 
53

Oil
10/01/2014 - 12/31/2014
 
20,000

 
90.00

 
97.00
 
106

Oil
10/01/2014 - 12/31/2014
 
12,000

 
90.00

 
97.90
 
66

Oil
10/01/2014 - 12/31/2014
 
15,000

 
90.00

 
97.90
 
83

Oil
10/01/2014 - 12/31/2014
 
15,000

 
90.00

 
98.00
 
83

Oil
10/01/2014 - 12/31/2014
 
15,000

 
90.00

 
101.15
 
90

Oil
10/01/2014 - 12/31/2014
 
10,000

 
90.00

 
103.75
 
61

Oil
10/01/2014 - 12/31/2014
 
10,000

 
90.00

 
103.88
 
62

Oil
10/01/2014 - 12/31/2014
 
10,000

 
90.00

 
104.15
 
62

Oil
01/01/2015 - 12/31/2015
 
20,000

 
80.00

 
100.00
 
290

Oil
01/01/2015 - 12/31/2015
 
20,000

 
80.00

 
101.00
 
323

Oil
01/01/2015 - 12/31/2015
 
20,000

 
83.00

 
96.12
 
315

Oil
01/01/2015 - 12/31/2015
 
20,000

 
83.00

 
97.00
 
343

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
 
645

Oil
01/01/2015 - 12/31/2015
 
20,000

 
85.00

 
105.10
 
798

Total open oil costless collar contracts
 
 
 
 
 
 
 
4,159


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
10/01/2014 - 12/31/2014
 
100,000

 
3.00

 
5.15

 
(3
)
Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.21

 
(1
)
Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.22

 
(1
)
Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.37

 

Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.42

 

Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.50

 
4.90

 
(2
)
Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.75

 
4.75

 
2

Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
3.75

 
4.77

 
2

Natural Gas
10/01/2014 - 12/31/2014
 
100,000

 
4.00

 
4.60

 
12

Natural Gas
10/01/2014 - 12/31/2015
 
100,000

 
3.75

 
4.36

 
6

Natural Gas
10/01/2014 - 12/31/2015
 
100,000

 
3.75

 
4.45

 
43

Natural Gas
01/01/2015 - 03/31/2015
 
200,000

 
4.00

 
4.84

 
45

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

 
3.75

 
4.60

 
96

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

 
3.75

 
4.65

 
116

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

 
3.75

 
5.04

 
378

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

 
3.75

 
5.34

 
225

Total open natural gas costless collar contracts
 
 
 
 
 
 
 
918

Commodity
Calculation Period
 
Notional Quantity
(Gal/month)
 
Fixed Price
($/Gal)
 
Fair Value of Asset (Liability)
(thousands)
Propane
10/01/2014 - 12/31/2014
 
116,000

 
0.950

 
(45
)
Propane
10/01/2014 - 12/31/2014
 
116,000

 
1.003

 
(16
)
Propane
10/01/2014 - 12/31/2014
 
60,000

 
1.015

 
(6
)
Propane
10/01/2014 - 12/31/2014
 
84,000

 
1.143

 
24

Propane
10/01/2014 - 12/31/2014
 
68,000

 
1.150

 
21

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

 
1.000

 
(48
)
Propane
01/01/2015 - 12/31/2015
 
100,000

 
1.030

 
4

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

 
1.073

 
37

Normal Butane
10/01/2014 - 12/31/2014
 
17,500

 
1.540

 
21

Normal Butane
10/01/2014 - 12/31/2014
 
45,500

 
1.550

 
45

Isobutane
10/01/2014 - 12/31/2014
 
22,000

 
1.640

 
27

Isobutane
10/01/2014 - 12/31/2014
 
37,000

 
1.640

 
56

Natural Gasoline
10/01/2014 - 12/31/2014
 
30,000

 
1.970

 
(5
)
Natural Gasoline
10/01/2014 - 12/31/2014
 
41,000

 
2.000

 
6

   Total open NGL swap contracts
 
 
 
 
 
 
121

Total open derivative financial instruments
 
 
 
 
 
 
$
5,198

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 September 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
$
1,425

 
$
(534
)
 
$
891

 
$

   Other assets
568

 
(243
)
 
325

 

Counterparty B

 

 

 
 
   Current assets
1,369

 
(556
)
 
813

 

   Other assets
461

 
(233
)
 
228

 

Counterparty C

 

 

 
 
   Current assets
2,991

 
(1,568
)
 
1,423

 

   Other assets
1,060

 
(620
)
 
440

 

Counterparty D
 
 
 
 
 
 
 
   Current assets
9

 
(8
)
 
1

 

   Other assets

 

 

 

Counterparty E
 
 
 
 
 
 
 
   Current assets
966

 
(165
)
 
801

 

   Other assets
367

 
(82
)
 
285

 

Total
$
9,216

 
$
(4,009
)
 
$
5,207

 
$


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 September 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
$
534

 
$
(534
)
 
$

 
$

   Other liabilities
243

 
(243
)
 

 

Counterparty B

 

 

 

   Current liabilities
556

 
(556
)
 

 

   Other liabilities
233

 
(233
)
 

 

Counterparty C

 

 

 

   Current liabilities
1,568

 
(1,568
)
 

 

   Other liabilities
629

 
(620
)
 
9

 

Counterparty D
 
 
 
 
 
 
 
   Current liabilities
8

 
(8
)
 

 

   Other liabilities

 

 

 

Counterparty E
 
 
 
 
 
 
 
   Current liabilities
165

 
(165
)
 

 

   Other liabilities
82

 
(82
)
 

 

Total
$
4,018

 
$
(4,009
)
 
$
9

 
$

 

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 
 September 30,
 
Nine Months Ended 
 September 30,
Type of Instrument
Location in Condensed Consolidated Statement of Operations
 
2014
 
2013
 
2014
 
2013
Derivative Instrument
 
 
 
 
 
 
 
 
 
Oil
Revenues: Realized loss on derivatives
 
$
(816
)
 
$
(1,519
)
 
$
(4,523
)
 
$
(1,984
)
Natural Gas
Revenues: Realized gain (loss) on derivatives
 
19

 
161

 
(757
)
 
790

NGL
Revenues: Realized gain (loss) on derivatives
 
96

 
193

 
(178
)
 
675

Realized loss on derivatives
 
(701
)
 
(1,165
)
 
(5,458
)
 
(519
)
Oil
Revenues: Unrealized gain (loss) on derivatives
 
14,106

 
(8,132
)
 
6,359

 
(6,818
)
Natural Gas
Revenues: Unrealized gain (loss) on derivatives
 
1,933

 
57

 
1,362

 
(132
)
NGL
Revenues: Unrealized gain (loss) on derivatives
 
254

 
(1,252
)
 
229

 
324

Unrealized gain (loss) on derivatives
 
16,293

 
(9,327
)
 
7,950

 
(6,626
)
Total
 
 
$
15,592

 
$
(10,492
)
 
$
2,492

 
$
(7,145
)
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 September 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 September 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 September 30, 2014 and December 31, 2013 (in thousands). 
 
Fair Value Measurements at
September 30, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Oil, natural gas and NGL derivatives
$

 
$
5,207

 
$

 
$
5,207

Oil, natural gas and NGL derivatives

 
(9
)
 

 
(9
)
Total
$

 
$
5,198

 
$

 
$
5,198

 
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 September 30, 2014 and December 31, 2013 (in thousands).
  
Fair Value Measurements at
September 30, 2014 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$

 
$

 
$
(3,458
)
 
$
(3,458
)
Total
$

 
$

 
$
(3,458
)
 
$
(3,458
)
 
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 September 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 $6.9 million at September 30, 2014. The Company paid $1.5 million and $2.0 million in processing and transportation fees under this agreement during the three months ended September 30, 2014 and 2013, respectively, and $4.3 million and $3.8 million during the nine months ended September 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 replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $57.9 million at September 30, 2014.
At September 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 $21.9 million at September 30, 2014, which it 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 September 30, 2014 and December 31, 2013 (in thousands).
 
September 30,
2014
 
December 31,
2013
Accrued evaluated and unproved and unevaluated property costs
$
97,101

 
$
52,605

Accrued support equipment and facilities costs
2,488

 

Accrued stock-based compensation

 
56

Accrued lease operating expenses
9,870

 
6,251

Accrued interest on borrowings under Credit Agreement
158

 
141

Accrued asset retirement obligations
540

 
175

Accrued partners’ share of joint interest charges
3,648

 
1,173

Other
5,556

 
3,586

Total accrued liabilities
$
119,361

 
$
63,987

Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the nine months ended September 30, 2014 and 2013 (in thousands).
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Cash paid for interest expense, net of amounts capitalized
$
3,667

 
$
2,110

Asset retirement obligations related to mineral properties
3,305

 
889

Asset retirement obligations related to support equipment and facilities
132

 
4

Increase (decrease) in liabilities for oil and natural gas properties capital expenditures
43,692

 
(6,288
)
Increase (decrease) in liabilities for support equipment and facilities
2,488

 
(1,100
)
Increase in liabilities for accrued cost to issue equity

 
456

Issuance of restricted stock units for Board and advisor services
313

 
186

Issuance of common stock for advisor services
13

 
25

Stock-based compensation expense recognized as liability
789

 
715

Transfer of inventory from oil and natural gas properties
300

 
201

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

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 the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.
For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: 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.
Third Quarter and Year-to-Date Highlights
Our total oil equivalent production for the third quarter of 2014 was 1.5 million BOE. Our average daily oil equivalent production for the third quarter of 2014 was 16,096 BOE per day, of which 9,123 Bbl per day, or 57%, was oil and 41.8 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 third quarter of 2014 of 839,000 Bbl and our average daily oil production of 9,123 Bbl per day were also record quarterly results. We achieved these results despite having as much as 15 to 20% of our total production capacity shut in or restricted at various times during the third quarter while offsetting wells were being drilled and completed and pipeline connections were being made. For the nine months ended September 30, 2014, our total oil equivalent production was 4.0 million BOE, averaging 14,490 BOE per day, and our total oil production was 2.3 million Bbl, averaging 8,432 Bbl per day. These results were also the best reported for any nine-month period in our Company’s history.

24


During the third quarter of 2014, our oil and natural gas revenues were $96.6 million, an increase of 18% from oil and natural gas revenues of $81.9 million during the third quarter of 2013. This increase was primarily attributable to the 36% increase in our oil production to 839,000 Bbl in the third quarter of 2014, as compared to 617,000 Bbl produced in the third quarter of 2013. This increase in oil production is primarily attributable to faster drilling operations and better completions in the Eagle Ford shale as well as better-than-expected initial production contributions from newly drilled wells in the Permian Basin. For the nine months ended September 30, 2014, our oil and natural gas revenues were $274.6 million, an increase of 38% from oil and natural gas revenues of $199.4 million for the first nine months of 2013. For the three months ended September 30, 2014, our Adjusted EBITDA was $66.8 million, an increase of 9% from Adjusted EBITDA of $61.5 million during the three months ended September 30, 2013. For the nine months ended September 30, 2014, our Adjusted EBITDA was $192.6 million, an increase of 35% from $142.9 million during the nine months ended September 30, 2013. These oil and natural gas revenues and Adjusted EBITDA values for the nine months ended September 30, 2014 were the best reported for any nine-month period 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 September 5, 2014, the borrowing base under our revolving credit facility increased from $385.0 million to $450.0 million based on our lenders’ review of our proved oil and natural gas reserves at July 31, 2014. At September 30, 2014, the Company had borrowings outstanding of $250.0 million and $0.6 million in letters of credit issued under the credit facility. From October 1, 2014 through November 5, 2014, the Company borrowed an additional $40.0 million under its revolving credit facility to finance a portion of its working capital requirements and capital expenditures and the acquisition of additional leasehold interests. At November 5, 2014, the Company had $290.0 million in borrowings outstanding under its revolving credit facility and approximately $0.6 million in outstanding letters of credit issued pursuant to such facility. We expect future increases to our borrowing base as the result of anticipated increases in our proved oil and natural gas reserves, and particularly our proved developed oil and natural gas reserves.
Our remaining 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 expanding our delineation and development efforts and building reserves in the Permian Basin in Southeast New Mexico and West Texas. As of November 5, 2014, we were operating four contracted drilling rigs — two in the Eagle Ford shale and two in the Permian Basin. Because of the timing of the addition of the second 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 have a material impact on our operations and financial results beginning in 2015. In addition, we have decided to further accelerate our Permian Basin drilling program by adding at least one additional rig at the beginning of 2015.
A subsidiary of Chesapeake Energy Corporation (“Chesapeake”) is in the process of drilling up to 45 gross (8.7 net) Haynesville shale wells on our Elm Grove acreage in southern Caddo Parish, Louisiana through early 2016. 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 had three rigs operating on these properties during the third quarter of 2014. The anticipated capital expenditures associated with this drilling program constitute approximately 10% our anticipated capital expenditures in 2014. These wells are being drilled and completed in a multi-well batch mode, and as of November 5, 2014, Chesapeake had completed and placed nine gross (2.0 net to the Company) wells on production, five late in the third quarter and four at the start of the fourth quarter. As of November 5, 2014, these nine gross (2.0 net) wells each were producing between 8 and 12 MMcf (gross) of natural gas per day, or a total of approximately 17 MMcf of natural gas per day net to our interest.
As a result of (i) our determination to operate two drilling rigs in the Permian Basin for the remainder of 2014, (ii) the ongoing and anticipated Chesapeake drilling activity in the Haynesville shale and (iii) 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 September 30, 2014, we had incurred $459.5 million, or approximately 81%, of this anticipated 2014 capital expenditure budget.
We had two contracted drilling rigs operating in the Permian Basin during the third quarter of 2014 — one in Loving County, Texas and the other in Lea County, New Mexico. During the third quarter of 2014, we completed and began producing oil and natural gas from five gross (4.6 net) operated Permian Basin wells. We completed three operated wells in our Wolf prospect area in Loving County, Texas — the Norton Schaub #1H, the Johnson 44-02S-B53 #204H and the Arno #1H wells — and two operated wells in our Ranger prospect area in Lea County, New Mexico — the Pickard State 20-18-34 #1H and the Pickard State 20-18-34 #2H wells. The Norton Schaub #1H, the Pickard State 20-18-34 #1H and the Pickard State 20-18-34 #2H wells began producing in July, and the Johnson 44-02S-B53 #204H and the Arno #1H wells were completed and began

25


testing in September. As a result, these five wells did not contribute fully to production volumes for the third quarter of 2014 or the nine months ended September 30, 2014.
In the Wolf prospect area in Loving County, Texas, the Johnson 44-02S-B53 #204H well flowed 1,286 BOE per day, including 793 Bbl of oil per day and 3.0 MMcf of natural gas per day (62% oil), at approximately 4,000 pounds per square inch (“psi”) flowing surface pressure on a 24/64th inch choke during its 24-hour initial potential test. This well was completed in the upper portion of the geopressured Wolfcamp formation, the Wolfcamp “A”, at approximately 11,200 feet true vertical depth. We drilled a 4,600-ft horizontal lateral in the Johnson 44-02S-B53 #204H well and completed it with 19 hydraulic fracturing stages, including approximately 200,000 Bbl of fluid and 9.4 million pounds of sand. The Arno #1H well flowed 1,110 BOE per day, including 300 Bbl of oil per day and 4.9 MMcf of natural gas per day (27% oil), at approximately 4,100 psi surface pressure on a 26/64th inch choke during its 24-hour initial potential test. This well was also completed in the Wolfcamp “A” bench at approximately 10,600 feet true vertical depth. We drilled a 5,400-ft horizontal lateral in the Arno #1H well and completed it with 22 hydraulic fracturing stages, including 226,000 Bbl of fluid and 10.6 million pounds of sand.  
The Johnson 44-02S-B53 #204H and the Arno #1H wells are the third and fourth successful tests of the Wolfcamp “A” bench in our Wolf prospect area, along with the Dorothy White #1H and Norton Schaub #1H wells. The Dorothy White #1H well continues to exhibit strong performance since being placed on production in January 2014. In approximately ten months on production, including its initial cleanup phase, the Dorothy White #1H well has produced approximately 246,000 BOE, including 166,000 Bbl of oil (67% oil), and is currently producing about 500 Bbl of oil per day and 1.5 MMcf of natural gas per day at almost 2,000 psi flowing surface pressure. The Norton Schaub #1H well has produced 85,000 BOE, including 59,000 Bbl of oil (69%), in three months of production and is currently producing about 420 Bbl of oil per day and 1.2 MMcf of natural gas per day at over 1,800 psi flowing surface pressure. Based on the success of these four wells, we intend to operate one of our two Permian Basin drilling rigs full time in the Loving County area in development mode throughout the remainder of 2014.
In the Ranger prospect area in Lea County, New Mexico, the Pickard State 20-18-34 #2H well flowed 270 BOE per day, including 232 Bbl of oil per day and 225 Mcf of natural gas per day (86% oil) at 1,150 psi surface pressure on an 18/64th inch choke during its 24-hour initial potential test. This well was completed in the Wolfcamp “D” bench at approximately 12,000 feet true vertical depth, and we believe it to be the northernmost horizontal completion in the Wolfcamp “D” formation in the Delaware Basin. We drilled a 4,300-ft horizontal lateral in the Pickard State 20-18-34 #2H well and completed it with 17 hydraulic fracturing stages, including 192,000 Bbl of fluid and 8.2 million pounds of sand. The Pickard State 20-18-34 #2H well has produced approximately 21,000 BOE in just over three months of production and is still producing approximately 200 BOE per day, including 150 Bbl of oil per day with gas-lift assist. Although these results are more modest than our other Permian Basin wells, we are encouraged by the geopressured nature of this horizon, other zones of interest and the stabilized production volumes of the current completion in the Wolfcamp “D” section. As a result, we expect to drill another Wolfcamp “D” test in early 2015, most likely in our Twin Lakes prospect area.
Elsewhere in the Ranger prospect area, our first two Second Bone Spring completions continue to perform well. The Ranger 33 State Com #1H well has produced 158,000 BOE, including 144,000 Bbl of oil (91% oil), in its first year on production and continues to produce about 300 Bbl of oil per day with gas-lift assist. The Pickard State 20-18-34 #1H well has produced 43,000 BOE, including 40,000 Bbl of oil (92% oil), after just over three months of production. Given the early success of the gas-lift assist on the Ranger 33 State Com #1H well, the Pickard State 20-18-34 #1H well was also equipped with gas-lift assist within about 30 days following its initial completion. At November 5, 2014, this well has produced an average of about 400 Bbl of oil per day with gas-lift assist over the last 30 days.
At November 5, 2014, we are operating two drilling rigs in the Eagle Ford shale, and both are currently drilling in La Salle County. Both rigs are “walking” rigs, and we plan to conduct batch drilling on our Eagle Ford properties using these two rigs for the remainder of 2014. During the third quarter of 2014, we completed and began producing oil and natural gas from ten gross (9.4 net) Eagle Ford wells, all of which were operated wells. We completed three Eagle Ford wells each on our Northcut and Martin Ranch leases in La Salle County, three wells on our Danysh leases in Karnes County and one well on our Lyssy lease in southern Wilson County. Immediately following the end of the third quarter, in early October, we also completed and began producing three gross (3.0 net) additional Eagle Ford wells on our Pawelek lease in Karnes County. The Northcut wells began producing in mid-July, the Danysh wells began producing at the end of July, the Martin Ranch wells began producing in mid-September and the Lyssy well began producing in late September. As a result, these wells did not contribute fully to production volumes for the third quarter of 2014 or the first nine months of 2014. Due to (i) batch drilling operations and other operating practices aimed at saving costs, improving operational efficiencies and increasing estimated ultimate recoveries, (ii) increased completion activity from industry in these areas, (iii) protection of producing wells during the drilling and completion of offsetting wells by both us and other operators and (iv) our continuing practice of managing bottomhole pressure by producing wells on restricted choke sizes, we had as much as 15 to 20% of our production capacity shut in or restricted at various times during the third quarter of 2014. For the nine months ended September 30, 2014, we completed and

26


began producing oil and natural gas from 31 gross (26.6 net) Eagle Ford wells, including 27 gross (25.5 net) operated wells and four gross (1.1 net) non-operated wells.
Our downspacing efforts in the Eagle Ford shale continue to achieve positive results. Since the beginning of the third quarter of 2014, we have drilled, completed and placed on production six gross (6.0 net) wells on our Danysh and Pawelek leases at 40 to 50-acre spacing. In the Danysh lease in Karnes County, the three most recent wells averaged 880 BOE per day, including 770 Bbl of oil per day and 650 Mcf of natural gas per day (88% oil), at 2,400 to 2,500 psi flowing surface pressure on a 14/64th inch choke during their 24-hour initial potential tests. On the Pawelek lease in Karnes County, the three most recent wells averaged 790 BOE per day, including 694 Bbl of oil per day and 575 Mcf of natural gas per day (88% oil), at 2,700 to 3,000 psi flowing surface pressure on a 14/64th inch choke during their 24-hour initial potential tests.
The three most recent wells drilled and placed on production on our Martin Ranch lease were drilled at 40-acre spacing with positive initial test results. The 24-hour initial potential tests from these three wells averaged approximately 790 BOE per day, including 730 Bbl of oil per day and 380 Mcf of natural gas per day (92% oil), at flowing surface pressures ranging from 1,900 to 2,750 psi on a 14/64th inch choke. We will continue to test 40 to 50-acre spacing on our other properties in northwest La Salle County throughout the remainder of 2014. Given the results from our leases in both the central and western portions of the Eagle Ford shale thus far, we currently expect to develop our remaining acreage in these areas on 40 to 50-acre spacing.
At September 30, 2014, our estimated total proved oil and natural gas reserves were 61.0 million BOE, including 21.5 million Bbl of oil and 236.7 Bcf of natural gas, with a PV-10 of $952.0 million and a Standardized Measure of $835.1 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 September 30, 2013, our estimated proved oil and natural gas reserves were 44.2 million BOE, including 13.9 million Bbl of oil and 182.0 Bcf of natural gas. Our proved oil reserves of 21.5 million Bbl at September 30, 2014 increased 55%, as compared to 13.9 million Bbl at September 30, 2013, and 32%, 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 $92.39 per Bbl for the three months ended September 30, 2014, as compared to $104.15 per Bbl for the three months ended September 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 at Midland oil price index less transportation costs. We realized a weighted average natural gas price of $4.95 per Mcf for the three months ended September 30, 2014, as compared to $4.71 per Mcf for the three months ended September 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 production from the Permian Basin due to natural gas liquids. 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 third quarter of 2014. Since the end of the second quarter of 2014, oil prices have declined significantly and at November 5, 2014, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date closed at $78.68 per Bbl. We are mindful of this recent decline in oil prices and are considering any adjustments that may be required to our operating plans and capital expenditures for 2015 as a result.
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 October 1, 2014, we acquired an additional 27,700 gross (20,200 net) acres in this area, primarily in Loving County, Texas and in Lea and Eddy Counties, New Mexico. Including these acreage acquisitions, at October 1, 2014, our total Permian Basin acreage position was approximately 98,400 gross (65,000 net) acres. We have also been actively acquiring additional Eagle Ford acreage in South Texas. Between January 1, 2014 and October 1, 2014, we acquired 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 September 30, 2014, December 31, 2013 and September 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

27


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.
 
September 30,
2014
 
December 31,
2013
 
September 30,
2013
Estimated Proved Reserves Data: (1) (2)
 
 
 
 
 
Estimated proved reserves:
 
 
 
 
 
Oil (MBbl)(3)
21,519

 
16,362

 
13,878

Natural Gas (Bcf)(4)
236.7

 
212.2

 
182.0

Total (MBOE)(5)
60,969

 
51,729

 
44,211

Estimated proved developed reserves:
 
 
 
 
 
Oil (MBbl)(3)
12,192

 
8,258

 
6,859

Natural Gas (Bcf)(4)
78.3

 
53.5

 
56.9

Total (MBOE)(5)
25,242

 
17,168

 
16,338

Percent developed
41.4
%
 
33.2
%
 
37.0
%
Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MBbl)(3)
9,327

 
8,104

 
7,019

Natural Gas (Bcf)(4)
158.4

 
158.7

 
125.1

Total (MBOE)(5)
35,727

 
34,561

 
27,873

PV-10(6) (in millions)
$
952.0

 
$
655.2

 
$
538.6

Standardized Measure(7) (in millions)
$
835.1

 
$
578.7

 
$
486.1

_______________
(1)
Numbers in table may not total due to rounding.
(2)
Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from October 2013 through September 2014 were $95.56 per Bbl for oil and $4.236 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 October 2012 through September 2013 were $91.69 per Bbl for oil and $3.605 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 September 30, 2014, December 31, 2013 and September 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 September 30, 2014, December 31, 2013 and September 30, 2013 were, in millions, $116.9, $76.5 and $52.5, 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 September 30, 2014, our estimated total proved oil and natural gas reserves were 61.0 million BOE, including 21.5 million Bbl of oil and 236.7 Bcf of natural gas, with a PV-10 of $952.0 million and a Standardized Measure of $835.1 million. At December 31, 2013, our estimated total 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 September 30, 2013, our estimated total proved oil and natural gas reserves were

28


44.2 million BOE, including 13.9 million Bbl of oil and 182.0 Bcf of natural gas. Our proved oil reserves of 21.5 million Bbl at September 30, 2014 increased 32%, as compared to 16.4 million Bbl at December 31, 2013, and 55%, as compared to 13.9 million Bbl at September 30, 2013. During the nine months ended September 30, 2014, our proved developed reserves increased 47% from 17.2 million BOE at December 31, 2013 to 25.2 million BOE at September 30, 2014. Year-over-year, our proved developed reserves increased 54% from 16.3 million BOE at September 30, 2013. At September 30, 2014, approximately 41% of our total proved reserves were proved developed reserves, 35% of our total proved reserves were oil and 65% 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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
(Unaudited)
 
(Unaudited)
 
(Unaudited)
 
(Unaudited)
Operating Data:
 
 
 
 
 
 
 
Revenues (in thousands):(1)
 
 
 
 
 
 
 
Oil
$
77,546

 
$
64,226

 
$
219,714

 
$
157,528

Natural gas
19,071

 
17,642

 
54,891

 
41,839

Total oil and natural gas revenues
96,617

 
81,868

 
274,605

 
199,367

Realized loss on derivatives
(701
)
 
(1,165
)
 
(5,458
)
 
(519
)
Unrealized gain (loss) on derivatives
16,293

 
(9,327
)
 
7,950

 
(6,626
)
Total revenues
$
112,209

 
$
71,376

 
$
277,097

 
$
192,222

Net Production Volumes:(1)
 
 
 
 
 
 
 
Oil (MBbl)(2)
839

 
617

 
2,302

 
1,524

Natural gas (Bcf)(3)
3.8

 
3.7

 
9.9

 
10.0

Total oil equivalent (MBOE)(4)
1,481

 
1,240

 
3,956

 
3,184

Average daily production (BOE/d)(5)
16,096