10-Q 1 mtdr-2013630x10q.htm 10-Q MTDR-2013.6.30-10Q

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 June 30, 2013
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-35410
 _________________________________________________________  
Matador Resources Company
(Exact name of registrant as specified in its charter)
  _________________________________________________________ 
 
Texas
27-4662601
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
5400 LBJ Freeway, Suite 1500
Dallas, Texas
75240
(Address of principal executive offices)
(Zip Code)
(972) 371-5200
(Registrant’s telephone number, including area code)
 _________________________________________________________  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     x  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No
As of August 8, 2013, there were 55,844,162 shares of the registrant’s common stock, par value $0.01 per share, outstanding.



MATADOR RESOURCES COMPANY
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2013
INDEX
 
Page



Part I – FINANCIAL INFORMATION
Item 1. Financial Statements
Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED
(In thousands, except par value and share data)
 
June 30,
2013
 
December 31,
2012
ASSETS
 
 
 
Current assets
 
 
 
Cash
$
5,105

 
$
2,095

Certificates of deposit
61

 
230

Accounts receivable
 
 
 
Oil and natural gas revenues
25,193

 
24,422

Joint interest billings
1,792

 
4,118

Other
766

 
974

Derivative instruments
3,978

 
4,378

Lease and well equipment inventory
597

 
877

Prepaid expenses
1,318

 
1,103

Total current assets
38,810

 
38,197

Property and equipment, at cost
 
 
 
Oil and natural gas properties, full-cost method
 
 
 
Evaluated
912,618

 
763,527

Unproved and unevaluated
168,275

 
149,675

Other property and equipment
28,428

 
27,258

Less accumulated depletion, depreciation and amortization
(419,066
)
 
(349,370
)
Net property and equipment
690,255

 
591,090

Other assets
 
 
 
Derivative instruments
3,459

 
771

Deferred income taxes
510

 
411

Other assets
1,677

 
1,560

Total other assets
5,646

 
2,742

Total assets
$
734,711

 
$
632,029

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
35,959

 
$
28,120

Accrued liabilities
48,512

 
59,179

Royalties payable
6,335

 
6,541

Derivative instruments
257

 
670

Advances from joint interest owners

 
1,515

Income taxes payable
78

 

Deferred income taxes
510

 
411

Other current liabilities
87

 
56

Total current liabilities
91,738

 
96,492

Long-term liabilities
 
 
 
Borrowings under Credit Agreement
245,000

 
150,000

Asset retirement obligations
5,881

 
5,109

Other long-term liabilities
2,067

 
1,324

Total long-term liabilities
252,948

 
156,433

Commitments and contingencies (Note 9)


 


Shareholders’ equity
 
 
 
Common stock - $0.01 par value, 80,000,000 shares authorized; 57,139,755 and 56,778,718 shares issued; and 55,837,912 and 55,577,667 shares outstanding, respectively
571

 
568

Additional paid-in capital
405,614

 
404,311

Retained deficit
(5,395
)
 
(15,010
)
Treasury stock, at cost, 1,301,843 and 1,201,051 shares, respectively
(10,765
)
 
(10,765
)
Total shareholders’ equity
390,025

 
379,104

Total liabilities and shareholders’ equity
$
734,711

 
$
632,029


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED
(In thousands, except per share data)
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2013
 
2012
 
2013
 
2012
Revenues
 
 
 
 
 
 
 
Oil and natural gas revenues
$
58,179

 
$
36,078

 
$
117,498

 
$
65,242

Realized gain on derivatives
254

 
4,713

 
646

 
7,776

Unrealized gain on derivatives
7,526

 
15,114

 
2,701

 
11,844

Total revenues
65,959

 
55,905

 
120,845

 
84,862

Expenses
 
 
 
 
 
 
 
Production taxes and marketing
4,451

 
2,619

 
8,548

 
4,783

Lease operating
10,140

 
6,375

 
21,040

 
11,020

Depletion, depreciation and amortization
20,234

 
19,913

 
48,466

 
31,119

Accretion of asset retirement obligations
80

 
58

 
161

 
111

Full-cost ceiling impairment

 
33,205

 
21,229

 
33,205

General and administrative
4,149

 
4,093

 
8,751

 
7,882

Total expenses
39,054

 
66,263

 
108,195

 
88,120

Operating income (loss)
26,905

 
(10,358
)
 
12,650

 
(3,258
)
Other income (expense)
 
 
 
 
 
 
 
Net loss on asset sales and inventory impairment
(192
)
 
(60
)
 
(192
)
 
(60
)
Interest expense
(1,609
)
 
(1
)
 
(2,880
)
 
(309
)
Interest and other income
47

 
30

 
115

 
103

Total other expense
(1,754
)
 
(31
)
 
(2,957
)
 
(266
)
Income (loss) before income taxes
25,151

 
(10,389
)
 
9,693

 
(3,524
)
Income tax provision (benefit)
 
 
 
 
 
 
 
Current
32

 

 
78

 

Deferred

 
(3,713
)
 

 
(649
)
Total income tax provision (benefit)
32

 
(3,713
)
 
78

 
(649
)
Net income (loss)
$
25,119

 
$
(6,676
)
 
$
9,615

 
$
(2,875
)
Earnings (loss) per common share
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Class A
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Class B
$

 
$

 
$

 
$
0.07

Diluted
 
 
 
 
 
 
 
Class A
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Class B
$

 
$

 
$

 
$
0.07

Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Class A
55,839

 
55,271

 
55,729

 
52,434

Class B

 

 

 
210

Total
55,839

 
55,271

 
55,729

 
52,644

Diluted
 
 
 
 
 
 
 
Class A
55,937

 
55,271

 
55,819

 
52,434

Class B

 

 

 
210

Total
55,937

 
55,271

 
55,819

 
52,644


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY - UNAUDITED
(In thousands)
For the Six Months Ended June 30, 2013
 
Common Stock
 
Additional
Paid-In Capital
 
Retained Deficit
 
Treasury Stock
 
 
 
Shares
 
Amount
 
 
 
Shares
 
Amount
 
Total
Balance at January 1, 2013
56,779

 
$
568

 
$
404,311

 
$
(15,010
)
 
1,201

 
$
(10,765
)
 
$
379,104

Common stock issued to Board advisors
3

 

 
25

 

 

 

 
25

Stock options expense related to equity based awards

 

 
537

 

 

 

 
537

Liability based stock option awards settled

 

 
64

 

 

 

 
64

Changes in fair value for liability based awards for which grant date fair value is in excess of fair value

 

 
2

 

 

 

 
2

Restricted stock issued
358

 
3

 
(3
)
 

 

 

 

Restricted stock forfeited

 

 
(22
)
 

 
101

 

 
(22
)
Restricted stock and restricted stock units expense

 

 
700

 

 

 

 
700

Current period net income

 

 

 
9,615

 

 

 
9,615

Balance at June 30, 2013
57,140

 
$
571

 
$
405,614

 
$
(5,395
)
 
1,302

 
$
(10,765
)
 
$
390,025


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED
(In thousands)
 
Six Months Ended 
 June 30,
 
2013
 
2012
Operating activities
 
 
 
Net income (loss)
$
9,615

 
$
(2,875
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 
 
 
Unrealized gain on derivatives
(2,701
)
 
(11,844
)
Depletion, depreciation and amortization
48,466

 
31,119

Accretion of asset retirement obligations
161

 
111

Full-cost ceiling impairment
21,229

 
33,205

Stock-based compensation expense
1,524

 
(172
)
Deferred income tax provision

 
(649
)
Net loss on asset sales and inventory impairment
192

 
60

Changes in operating assets and liabilities
 
 
 
Accounts receivable
1,763

 
(2,761
)
Lease and well equipment inventory
280

 
(98
)
Prepaid expenses
(215
)
 
(385
)
Other assets
(117
)
 
59

Accounts payable, accrued liabilities and other current liabilities
4,615

 
1,687

Royalties payable
(206
)
 
3,642

Advances from joint interest owners
(1,515
)
 

Income taxes payable
78

 

Other long-term liabilities
743

 
427

Net cash provided by operating activities
83,912

 
51,526

Investing activities
 
 
 
Oil and natural gas properties capital expenditures
(173,989
)
 
(134,425
)
Expenditures for other property and equipment
(2,081
)
 
(3,521
)
Purchases of certificates of deposit
(61
)
 
(266
)
Maturities of certificates of deposit
230

 
1,335

Net cash used in investing activities
(175,901
)
 
(136,877
)
Financing activities
 
 
 
Repayments of borrowings under Credit Agreement

 
(123,000
)
Borrowings under Credit Agreement
95,000

 
70,000

Proceeds from issuance of common stock

 
146,510

Swing sale profit contribution

 
24

Cost to issue equity

 
(11,599
)
Proceeds from stock options exercised

 
2,660

Taxes paid related to net share settlement of stock-based compensation
(1
)
 

Payment of dividends - Class B

 
(96
)
Net cash provided by financing activities
94,999

 
84,499

Increase (decrease) in cash
3,010

 
(852
)
Cash at beginning of period
2,095

 
10,284

Cash at end of period
$
5,105

 
$
9,432

Supplemental disclosures of cash flow information (Note 10)
 
 
 

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

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



NOTE 1 - NATURE OF OPERATIONS
Matador Resources Company (“Matador” and, collectively, with its subsidiaries, the “Company”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource 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 Southeast New Mexico and West Texas. The Company also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, the Company has a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where the Company is testing the Meade Peak shale.
On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011, the former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.
MRC Energy Company holds the primary assets of the Company and has four wholly-owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in Southeast New Mexico. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP, which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations and also transports limited quantities of third-party natural gas.
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, 2012 filed with the SEC (the “Annual Report”). All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of the Company’s consolidated financial position as of June 30, 2013, consolidated results of operations for the three and six months ended June 30, 2013 and 2012, consolidated changes in shareholders’ equity for the six months ended June 30, 2013 and consolidated cash flows for the six months ended June 30, 2013 and 2012. Certain reclassifications have been made to prior period items to conform to the current period presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. Amounts as of December 31, 2012 are derived from the audited consolidated financial statements in the Annual Report.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results for the interim periods shown in this report are not necessarily indicative of results to be expected for the full year due in part to volatility in oil, natural gas and natural gas liquids prices, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, oil, natural gas and natural gas liquids supply and demand, market competition and interruptions of production.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of

7

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
 
Property and Equipment
The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized approximately $1.4 million and $1.1 million of its general and administrative costs for the six months ended June 30, 2013 and 2012, respectively. The Company capitalized approximately $0.8 million and $0.6 million of its interest expense for the six months ended June 30, 2013 and 2012, 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, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The need for a full-cost ceiling impairment is assessed on a quarterly basis. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs for developing these reserves. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.
The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements.
The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period July 2012 through June 2013, these average oil and natural gas prices were $88.13 per Bbl and $3.444 per MMBtu (million British thermal units), respectively. For the period July 2011 through June 2012, these average oil and natural gas prices were $92.17 per Bbl and $3.146 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were adjusted by property for energy content, transportation and marketing fees and regional price differentials. At June 30, 2013 and 2012, the Company’s oil and natural gas reserves estimates were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at June 30, 2013, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs for the three months ended June 30, 2013. At March 31, 2013, the Company’s net capitalized costs less related deferred 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 for the three months ended March 31, 2013. These charges are reflected in the Company’s unaudited condensed consolidated statement of operations for the six months ended June 30, 2013. At June 30, 2013, the Company retained a full valuation allowance against its deferred tax assets, and as a result, the Company recorded no deferred income tax provision to its unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2013. Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at June 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. The Company recorded an impairment charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million related to the full-cost ceiling limitation. Changes in oil and natural gas production rates, reserves

8

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.
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.
 
Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Dry holes are included in the amortization base immediately upon determination that the well is not productive.

Earnings Per Common Share
The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
Prior to the consummation of the Company’s initial public offering in February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during the six months ended June 30, 2013 and 2012 totaled zero and $27,643, respectively. Class B dividends declared during the fourth quarter of 2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356. As of June 30, 2013, the Company had not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Company’s initial public offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the common stock.
The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and undistributed earnings (loss) per common share as reported for the three and six months ended June 30, 2013 and 2012 (in thousands, except per share data).

9

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
2013
 
2012
 
2013
 
2012
Net income (loss) — numerator
 
 
 
 
 
 
 
Net income (loss)
$
25,119

 
$
(6,676
)
 
$
9,615

 
$
(2,875
)
Less dividends to Class B shareholders — distributed earnings

 

 

 
(28
)
Undistributed earnings (loss)
$
25,119

 
$
(6,676
)
 
$
9,615

 
$
(2,903
)
Weighted average common shares outstanding — denominator
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Class A
55,839

 
55,271

 
55,729

 
52,434

Class B

 

 

 
210

Total
55,839

 
55,271

 
55,729

 
52,644

Diluted
 
 
 
 
 
 
 
Class A
 
 
 
 
 
 
 
Weighted average common shares outstanding for basic earnings


 


 
 
 
 
                             (loss) per share
55,839

 
55,271

 
55,729

 
52,434

Dilutive effect of options and restricted stock units
98

 

 
90

 

Class A weighted average common shares outstanding - diluted
55,937

 
55,271

 
55,819

 
52,434

Class B
 
 
 
 
 
 
 
Weighted average common shares outstanding – no associated


 
 
 
 
 
 
                             dilutive shares

 

 

 
210

Total diluted weighted average common shares outstanding
55,937

 
55,271

 
55,819

 
52,644

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
2013
 
2012
 
2013
 
2012
Earnings (loss) per common share
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Class A
 
 
 
 
 
 
 
Distributed earnings
$

 
$

 
$

 
$

Undistributed earnings (loss)
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Total
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Class B
 
 
 
 
 
 
 
Distributed earnings
$

 
$

 
$

 
$
0.13

Undistributed earnings
$

 
$

 
$

 
$
(0.06
)
Total
$

 
$

 
$

 
$
0.07

Diluted
 
 
 
 
 
 
 
Class A
 
 
 
 
 
 
 
Distributed earnings
$

 
$

 
$

 
$

Undistributed earnings (loss)
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Total
$
0.45

 
$
(0.12
)
 
$
0.17

 
$
(0.06
)
Class B
 
 
 
 
 
 
 
Distributed earnings
$

 
$

 
$

 
$
0.13

Undistributed earnings
$

 
$

 
$

 
$
(0.06
)
Total
$

 
$

 
$

 
$
0.07

A total of 1,293,568 options to purchase shares of the Company’s Class A common stock and 139,963 restricted stock units were excluded from the calculations above for the three and six months ended June 30, 2012, because their effects were anti-dilutive. Additionally, 231,683 restricted shares, which are participating securities, were excluded from the calculations above for the three and six months ended June 30, 2012, as these security holders do not have the obligation to share in the losses of the Company.

10

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows Financial Accounting Standards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value.
Recent Accounting Pronouncements
Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU clarifies the scope of ASU 2011-11 to limit the application of ASU 2011-11 to derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The Company adopted ASU 2013-01 effective January 1, 2013, together with the adoption of ASU 2011-11. The adoption of ASUs 2013-01 and 2011-11 did not have a material effect on the Company’s consolidated financial statements but did require certain additional disclosures (see Note 7).
Balance Sheet. In December 2011, the FASB issued ASU 2011-11, Balance Sheet. The requirements amend the disclosure requirements related to offsetting in ASC 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The Company adopted ASU 2011-11 effective January 1, 2013, together with the adoption of ASU 2013-01. The adoption of ASUs 2011-11 and 2013-01 did not have a material effect on the Company’s consolidated financial statements but did require certain additional disclosures (see Note 7).

11

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

NOTE 3 - ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2013 (in thousands).
 
 
Beginning asset retirement obligations
$
5,769

Liabilities incurred during period
214

Liabilities settled during period
(1
)
Revisions in estimated cash flows
542

Accretion expense
161

Ending asset retirement obligations
6,685

Less: current asset retirement obligations(1)
(804
)
Long-term asset retirement obligations
$
5,881

 _______________
(1) 
Included in accrued liabilities in the Company’s unaudited condensed consolidated balance sheet at June 30, 2013.
NOTE 4 - REVOLVING CREDIT AGREEMENT
On September 28, 2012, the Company amended and restated its revolving credit agreement. This third amended and restated credit agreement (the “Credit Agreement”) increased the maximum facility amount from $400.0 million to $500.0 million. The Credit Agreement matures December 29, 2016. MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company.
The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2013, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2012, and on March 11, 2013, the borrowing base was increased from $215.0 million to $255.0 million. In connection with this borrowing base redetermination, the conforming borrowing base was increased to $220.0 million. At that time, the Company also amended the Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in the Company’s lending group, which also includes RBC as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. This March 11, 2013 redetermination constituted the regularly scheduled May 1 redetermination. In late April 2013, the Company requested an unscheduled redetermination of the borrowing base, and on June 4, 2013, the borrowing base was increased from $255.0 million to $280.0 million.
On August 7, 2013, the borrowing base under the Credit Agreement was increased to $350.0 million and the conforming borrowing base was increased to $275.0 million. At that time, the Company amended the Credit Agreement to provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2014 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million. This August redetermination constituted the regularly scheduled November 1 redetermination. The Company may request one additional unscheduled redetermination of its borrowing base prior to the next scheduled redetermination.
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. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.
 

12

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

NOTE 4 - REVOLVING CREDIT AGREEMENT - Continued

In connection with the March and June 2013 borrowing base redeterminations, the Company incurred $0.1 million of additional deferred loan costs. These costs were included with the remaining unamortized balance of the deferred loan costs incurred previously. As a result, total deferred loan costs were $1.7 million at June 30, 2013, and these costs are being amortized over the term of the agreement, which approximates the amortization of these costs using the effective interest method. At June 30, 2013, the Company had $245.0 million in borrowings outstanding under the Credit Agreement and approximately $1.2 million in outstanding letters of credit issued pursuant to the Credit Agreement. At June 30, 2013, the outstanding borrowings bore interest at an effective interest rate of approximately 3.6% per annum. Subsequent to June 30, 2013, the Company borrowed an additional $15.0 million to fund a portion of its working capital requirements and the acquisition of additional leasehold interests in Southeast New Mexico. At August 8, 2013, the Company had $260.0 million in borrowings outstanding under the Credit Agreement and approximately $1.2 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 or (ii) the Federal Funds Effective Rate on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 3.00% 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 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 1.75% to 4.00% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A 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 as interest expense and in its interest rate calculations and related disclosures. Key financial covenants under the Credit Agreement require the Company to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning June 30, 2014 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less.
Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s, along with its subsidiaries’, ability to take certain actions, including, but not limited to, the following:
incur indebtedness or grant liens on any of its assets;
enter into commodity hedging agreements;
declare or pay dividends, distributions or redemptions;
merge or consolidate;
make any loans or investments;
engage in transactions with affiliates; and
engage in certain asset dispositions, including a sale of all or substantially all of its 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 notes or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;
failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
bankruptcy or insolvency events involving the Company or its subsidiaries; and
a change of control, as defined in the Credit Agreement.
At June 30, 2013, the Company believes that it was in compliance with the terms of its Credit Agreement.


13

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

NOTE 5 - INCOME TAXES
Based upon its projections for the remainder of 2013, the Company anticipates incurring a small alternative minimum tax (“AMT”) liability for the year ending December 31, 2013, the proportionate shares of which are recorded as the current income tax provision for the three and six months ended June 30, 2013. The Company established a valuation allowance at September 30, 2012 and retained a full valuation allowance of approximately $6.7 million at June 30, 2013 due to uncertainties regarding the future realization of its net deferred tax assets. As a result, there was no income tax expense or benefit recorded for the three and six months ended June 30, 2013, other than the AMT liability noted above. The Company had a net loss for the three and six months ended June 30, 2012.
NOTE 6 - STOCK-BASED COMPENSATION
In March 2013, the Company granted awards of options to purchase 507,500 and 284,292 shares of the Company’s common stock at exercise prices of $8.21 per share and $8.18 per share, respectively, to certain of its employees. The fair value of these awards was approximately $2.8 million. The Company also granted awards of 324,771 shares of restricted stock to certain of its employees in March 2013. The fair value of these restricted stock awards was approximately $2.4 million. All of these awards vest over a term of three or four years.
In February 2013, options to purchase 408,000 shares of the Company’s common stock at $10.00 per share expired unexercised or were forfeited.
NOTE 7 - 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 loss. The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly traded securities. Comerica Bank, The Bank of Nova Scotia and RBC (or affiliates thereof) were the counterparties for our commodity derivatives at June 30, 2013. 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 also entered into various swap contracts to mitigate its exposure to fluctuations in oil prices, each with an established fixed price. 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 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 oil 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 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 last day of that contract period. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal

14

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

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

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, except for purity ethane, as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. The settlement price for purity ethane is the arithmetic average of any current month for delivery on the nearby month futures contracts as stated on the “Mont Belvieu Spot Gas Liquids Prices” on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume.
At June 30, 2013, 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 2013, 2014 and 2015.
At June 30, 2013, the Company had various swap contracts open and in place to mitigate its exposure to oil and 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 2013 and 2014.
 

15

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

NOTE 7 - 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 oil and natural gas liquids at June 30, 2013.
Commodity
Calculation Period
 
Notional
Quantity
(Bbl/month)
 
Price  Floor
($/Bbl)
 
Price
Ceiling
($/Bbl)
 
Fair Value of
Asset
(Liability)
(thousands)
Oil
07/01/2013 - 12/31/2013
 
20,000

 
85.00

 
102.25

 
$
(9
)
Oil
07/01/2013 - 12/31/2013
 
20,000

 
85.00

 
108.80

 
84

Oil
07/01/2013 - 12/31/2013
 
20,000

 
85.00

 
110.40

 
94

Oil
07/01/2013 - 12/31/2013
 
20,000

 
90.00

 
102.80

 
126

Oil
07/01/2013 - 12/31/2013
 
20,000

 
90.00

 
115.00

 
224

Oil
07/01/2013 - 06/30/2014
 
8,000

 
90.00

 
114.00

 
336

Oil
07/01/2013 - 06/30/2014
 
12,000

 
90.00

 
115.50

 
513

Oil
01/01/2014 - 12/31/2014
 
15,000

 
85.00

 
97.50

 
248

Oil
01/01/2014 - 12/31/2014
 
30,000

 
85.00

 
98.00

 
546

Oil
01/01/2014 - 12/31/2014
 
15,000

 
87.00

 
97.00

 
349

Oil
01/01/2014 - 12/31/2014
 
20,000

 
88.00

 
95.60

 
444

Oil
01/01/2014 - 12/31/2014
 
20,000

 
90.00

 
97.00

 
763

Oil
01/01/2014 - 12/31/2014
 
15,000

 
90.00

 
97.90

 
642

Oil
01/01/2014 - 12/31/2014
 
15,000

 
90.00

 
98.00

 
637

Total open oil costless collar contracts
 
 
 
 
 
 
 
4,997

Commodity
Calculation Period
 
Notional
Quantity
(MMBtu/month)
 
Price Floor
($/MMBtu)
 
Price
Ceiling
($/MMBtu)
 
Fair Value of
Asset
(Liability)
(thousands)
Natural Gas
07/01/2013 - 07/31/2013
 
150,000

 
4.50

 
5.75

 
119

Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.00

 
3.83

 
(57
)
Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.00

 
4.95

 
9

Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.00

 
4.96

 
10

Natural Gas
07/01/2013 - 12/31/2013
 
150,000

 
3.00

 
4.24

 
(25
)
Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.25

 
4.41

 
14

Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.25

 
4.44

 
16

Natural Gas
07/01/2013 - 12/31/2013
 
100,000

 
3.50

 
4.37

 
55

Natural Gas
08/01/2013 - 12/31/2013
 
80,000

 
3.75

 
4.57

 
104

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

 
3.00

 
5.15

 
(26
)
Natural Gas
01/01/2014 - 12/31/2014
 
100,000

 
3.25

 
5.21

 
45

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

 
3.25

 
5.22

 
45

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

 
3.25

 
5.37

 
64

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

 
3.25

 
5.42

 
68

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

 
3.50

 
4.90

 
98

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

 
3.75

 
4.77

 
200

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

 
3.75

 
5.04

 
207

Total open natural gas costless collar contracts
 
 
 
 
 
 
 
946

Commodity
Calculation Period
 
Notional Quantity
(Bbl/month)
 
Fixed Price
($/Bbl)
 
Fair Value  of
Liability
(thousands)
Oil
07/01/2013 - 12/31/2013
 
10,000

 
90.20

 
(295
)
Oil
07/01/2013 - 12/31/2013
 
10,000

 
90.65

 
(269
)
Total open oil swap contracts
 
 
 
 
 
 
(564
)

16

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

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

Commodity
Calculation Period
 
Notional Quantity
(Gal/month)
 
Fixed Price
($/Gal)
 
Fair Value of Asset
(thousands)
Purity Ethane
07/01/2013 - 12/31/2013
 
110,000

 
0.335

 
57

Purity Ethane
07/01/2013 - 12/31/2013
 
110,000

 
0.355

 
71

Propane
07/01/2013 - 12/31/2013
 
53,000

 
0.953

 
30

Propane
07/01/2013 - 12/31/2013
 
106,000

 
0.960

 
65

Propane
07/01/2013 - 12/31/2013
 
53,000

 
1.001

 
45

Propane
01/01/2014 - 12/31/2014
 
116,000

 
0.950

 
141

Normal Butane
07/01/2013 - 12/31/2013
 
14,700

 
1.455

 
22

Normal Butane
07/01/2013 - 12/31/2013
 
14,700

 
1.560

 
32

Normal Butane
07/01/2013 - 12/31/2013
 
21,000

 
1.575

 
47

Normal Butane
07/01/2013 - 12/31/2013
 
117,000

 
1.575

 
268

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

 
1.540

 
75

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

 
1.550

 
211

Isobutane
07/01/2013 - 12/31/2013
 
7,000

 
1.515

 
11

Isobutane
07/01/2013 - 12/31/2013
 
7,000

 
1.625

 
16

Isobutane
07/01/2013 - 12/31/2013
 
43,500

 
1.675

 
110

Isobutane
07/01/2013 - 12/31/2013
 
23,000

 
1.675

 
62

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

 
1.640

 
114

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

 
1.640

 
184

Natural Gasoline
07/01/2013 - 12/31/2013
 
12,000

 
2.025

 
4

Natural Gasoline
07/01/2013 - 12/31/2013
 
12,000

 
2.085

 
8

Natural Gasoline
07/01/2013 - 12/31/2013
 
12,000

 
2.102

 
9

Natural Gasoline
07/01/2013 - 12/31/2013
 
36,000

 
2.105

 
29

Natural Gasoline
07/01/2013 - 12/31/2013
 
90,500

 
2.148

 
98

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

 
1.970

 
32

Natural Gasoline
01/01/2014 - 12/31/2014
 
41,000

 
2.000

 
60

Total open NGL swap contracts
 
 
 
 
 
1,801

Total open derivative financial instruments
 
 
 
 
 
$
7,180

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

17

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

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of June 30, 2013 (in thousands).
Derivative Instruments
Gross
amounts of
recognized
assets
 
Gross amounts
netted in the
consolidated
balance sheet
 
Net amounts of
assets
presented in the
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
Current assets
$
3,682

 
$
(1,823
)
 
$
1,859

 
$

Other assets
2,858

 
(1,467
)
 
1,391

 

Counterparty B

 

 

 
 
Current assets
2,239

 
(1,264
)
 
975

 
257

Other assets
2,859

 
(1,510
)
 
1,349

 

Counterparty C

 

 

 
 
Current assets
2,231

 
(1,087
)
 
1,144

 

Other assets
1,699

 
(980
)
 
719

 

Total
$
15,568

 
$
(8,131
)
 
$
7,437

 
$
257

The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its unaudited condensed consolidated balance sheet as of June 30, 2013 (in thousands). 
Derivative Instruments
Gross
amounts of
recognized
liabilities
 
Gross amounts
netted in the
consolidated
balance sheet
 
Net amounts of
liabilities
presented in the
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
Current liabilities
$
1,823

 
$
(1,823
)
 
$

 
$

Long-term liabilities
1,467

 
(1,467
)
 

 

Counterparty B

 

 

 

Current liabilities
1,521

 
(1,264
)
 
257

 
257

Long-term liabilities
1,510

 
(1,510
)
 

 

Counterparty C

 

 

 

Current liabilities
1,087

 
(1,087
)
 

 

Long-term liabilities
980

 
(980
)
 

 

Total
$
8,388

 
$
(8,131
)
 
$
257

 
$
257

 

18

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

NOTE 7 - 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, 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, 2012 (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
consolidated
balance sheet
 
Amounts subject to master netting arrangements presented on a gross basis
Counterparty A
 
 
 
 
 
 
 
Current assets
$
6,445

 
$
(2,373
)
 
$
4,072

 
$

Other assets
1,096

 
(370
)
 
726

 

Counterparty B

 

 

 
 
Current assets
530

 
(224
)
 
306

 
82

Other assets
384

 
(339
)
 
45

 

Total
$
8,455

 
$
(3,306
)
 
$
5,149

 
$
82

The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting, 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, 2012 (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
$
2,373

 
$
(2,373
)
 
$

 
$

Long-term liabilities
370

 
(370
)
 

 

Counterparty B

 

 

 
 
Current liabilities
894

 
(224
)
 
670

 
82

Long-term liabilities
339

 
(339
)
 

 

Total
$
3,976

 
$
(3,306
)
 
$
670

 
$
82


19

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

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands).
 
 
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Type of Instrument
Location in Condensed Consolidated Statement of Operations
 
2013
 
2012
 
2013
 
2012
Derivative Instrument
 
 
 
 
 
 
 
 
 
Oil
Revenues: Realized (loss) gain on derivatives
 
$
(228
)
 
$
719

 
$
(465
)
 
$
719

Natural Gas
Revenues: Realized gain on derivatives
 
105

 
3,994

 
629

 
7,057

NGL’s
Revenues: Realized gain on derivatives
 
377

 

 
482

 

Realized gain on derivatives
 
254

 
4,713

 
646

 
7,776

Oil
Revenues: Unrealized gain on derivatives
 
4,042

 
20,483

 
1,314

 
15,223

Natural Gas
Revenues: Unrealized gain (loss) on derivatives
 
2,323

 
(5,369
)
 
(189
)
 
(3,379
)
NGL’s
Revenues: Unrealized gain on derivatives
 
1,161

 

 
1,576

 

Unrealized gain on derivatives
 
7,526

 
15,114

 
2,701

 
11,844

Total
 
 
$
7,780

 
$
19,827

 
$
3,347

 
$
19,620

 
NOTE 8 - FAIR VALUE MEASUREMENTS
The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.

Level 1
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3
Unobservable inputs that are not corroborated by market data. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources.
Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
At June 30, 2013 and December 31, 2012, the carrying values reported on the unaudited condensed consolidated balance sheets for cash, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, advances from joint interest owners, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities and are classified at Level 1.
At June 30, 2013 and December 31, 2012, 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.
The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of June 30, 2013 and December 31, 2012 (in thousands).

20

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

NOTE 8 - FAIR VALUE MEASUREMENTS - Continued

 
 
Fair Value Measurements at
June 30, 2013 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Certificates of deposit
$

 
$
61

 
$

 
$
61

Oil, natural gas and NGL derivatives

 
7,437

 

 
7,437

Oil, natural gas and NGL derivatives

 
(257
)
 

 
(257
)
Total
$

 
$
7,241

 
$

 
$
7,241

 
Fair Value Measurements at
December 31, 2012 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Certificates of deposit
$

 
$
230

 
$

 
$
230

Oil, natural gas and NGL derivatives

 
5,149

 

 
5,149

Oil, natural gas and NGL derivatives

 
(670
)
 

 
(670
)
Total
$

 
$
4,709

 
$

 
$
4,709

Additional disclosures related to derivative financial instruments are provided in Note 7. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2.

21

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

NOTE 8 - FAIR VALUE MEASUREMENTS - Continued

The Company accounts for additions to asset retirement obligations and lease and well equipment inventory when adjusted for impairment at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis for the periods ended June 30, 2013 and December 31, 2012 (in thousands).
  
Fair Value Measurements at
June 30, 2013 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$

 
$

 
$
(756
)
 
$
(756
)
Lease and well equipment inventory

 

 
21

 
21

Total
$

 
$

 
$
(735
)
 
$
(735
)
 
Fair Value Measurements at
December 31, 2012 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets (Liabilities)
 
 
 
 
 
 
 
Asset retirement obligations
$

 
$

 
$
(1,243
)
 
$
(1,243
)
Lease and well equipment inventory

 

 
34

 
34

Total
$

 
$

 
$
(1,209
)
 
$
(1,209
)
For purposes of fair value measurement, the Company determined that additions and revisions to asset retirement obligations should be classified at Level 3. The Company recorded additions to asset retirement obligations and revisions of estimated cash flows of approximately $0.8 million for the six months ended June 30, 2013 and $1.2 million for the year ended December 31, 2012.
For purposes of fair value measurement, the Company determined that lease and well equipment inventory should be classified at Level 3 when adjusted for impairment. In 2012, the Company recorded an impairment to some of its equipment held in inventory consisting primarily of drilling rig parts of $425,000 and pipe and other equipment of $60,464. During the three months ended June 30, 2013, the Company recorded an impairment to some of its pipe held in inventory of $192,410. The Company periodically obtains estimates of the market value of its equipment held in inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
Office Lease
The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2013, the Company entered into the fifth amendment to its office lease agreement. This amendment increased the square footage of its corporate headquarters to 40,071 square feet effective July 1, 2013. The lease expires on June 30, 2022.
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 firm 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. The Company believes that its current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing

22

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

NOTE 9 - COMMITMENTS AND CONTINGENCIES - Continued

commitments under this agreement. The Company’s remaining aggregate undiscounted minimum commitments under this agreement are $13.7 million at June 30, 2013. The Company paid approximately $1.0 million and $1.8 million in processing and transportation fees under this agreement during the three and six months ended June 30, 2013.
 
Other Commitments
From time to time, the Company enters into contracts with third parties for drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which are typically for one year or less. Should the Company elect to terminate a contract and if the drilling contractor were unable to secure work for the contracted drilling rigs or if the drilling contractor were unable to secure work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under its drilling rig contracts were approximately $2.0 million at June 30, 2013.

In July 2013, the Company entered into a contract for a drilling rig to continue to explore and develop its acreage in the Eagle Ford shale in South Texas. Drilling operations under this contract are scheduled to commence in late August 2013 and the term of the contract is 180 days from the commencement date. Should the Company elect to terminate this contract and if the drilling contractor were unable to secure work for the rig or if the drilling contractor were unable to secure work for the rig at the same daily rate being charged to the Company, the Company would incur termination obligations. The Company’s maximum termination obligation under this contract was approximately $2.7 million at August 8, 2013.
At June 30, 2013, 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 minimum outstanding aggregate commitments for its participation in these wells of approximately $6.6 million at June 30, 2013, which it expects to incur within the next few months.
Legal Proceedings
Cynthia Fry Peironnet, et al. v. MRC Energy Company f/k/a Matador Resources Company. The Company is involved in a dispute over a mineral rights lease involving certain acreage in Louisiana. The dispute regards an extension of the term of a lease in Caddo Parish, Louisiana (the “Lease”) where the Company has drilled or participated in the drilling of both Cotton Valley and Haynesville shale wells. At issue are the deep rights below the Cotton Valley formation on approximately 1,805 gross acres where the Company has the right to participate for up to a 25% working interest, and also retains a small overriding royalty interest, in Haynesville shale wells drilled in units that include portions of the acreage. The Company’s total net revenue and overriding royalty interests in several non-operated Haynesville shale wells previously drilled on this acreage range from approximately 2% to 23%, and only portions of these interests are attributable to this acreage. The sum of the Company’s overriding royalty and net revenue interests attributable to this acreage from Haynesville wells previously drilled on this acreage comprises less than one net well.
The plaintiffs brought this claim against the Company on May 15, 2008 in the First Judicial District Court, Caddo Parish, Louisiana (the “Trial Court”). The plaintiffs sought (i) reformation or rescission of the lease extension, (ii) an accounting for additional royalty, (iii) monetary damages and (iv) attorney’s fees. During the pendency of the case in the Trial Court, the Company settled with one lessor who owned a 1/6th undivided interest in the minerals. The Trial Court rendered multiple rulings in favor of the Company, including a unanimous jury verdict in favor of the Company in the fall of 2010. Final judgment of the Trial Court was rendered in favor of the Company on June 6, 2011. On August 1, 2012, the Louisiana Second Circuit Court of Appeal (the “Court of Appeal”) affirmed in part and reversed in part the judgment of the Trial Court and remanded the case to the Trial Court for determination of damages. The Court of Appeal affirmed the Trial Court with respect to the 1/6th royalty owner that settled and also affirmed that the Company’s lease extension was unambiguous. Nonetheless, the Court of Appeal reformed the lease extension to cover only approximately 169 gross acres, holding that the deep rights covering the remaining 1,636 gross acres had expired. The Court of Appeal denied the Company’s motion for rehearing, and the Company and certain other defendants filed an appeal with the Louisiana Supreme Court. The Louisiana Supreme Court granted the requests to hear an appeal of the Court of Appeal’s decision, and in June 2013, the Louisiana Supreme Court reversed the decision of the Court of Appeal and reinstated the Trial Court judgment in its entirety. The plaintiffs have filed an application for rehearing with the Louisiana Supreme Court.
The Company believes that the facts of the case and the applicable law do not support the plaintiffs’ application for rehearing. In the opinion of management, it is remote that this litigation will have a material adverse impact on the Company’s financial position, results of operations or cash flows.

23

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

NOTE 9 - COMMITMENTS AND CONTINGENCIES - Continued

 
MRC Energy Company f/k/a Matador Resources Company, v. Orca ICI Development, J.V. The Company and Orca, a non-operator working interest owner, had various disputes regarding certain of the Company’s Eagle Ford shale wells and properties. Among other things, issues arose with respect to the rights and obligations of the Company and Orca under various agreements between the parties, and Orca sought the Company’s consent to Orca’s proposed assignment of its 50 percent working interest in the Cowey #3H and #4H wells to a non-industry person, despite the presence of a uniform maintenance of interest provision. On April 2, 2013, Orca brought suit against the Company in the 57th Judicial District Court of Bexar County, Texas and sought injunctive relief. The court denied Orca’s demand for injunctive relief, and on April 5, 2013, the Company moved to enforce arbitration provisions in the agreements between the parties. On April 22, 2013, the Company initiated an arbitration against Orca, seeking, among other things, a declaration that the Company could withhold its consent to Orca’s putative assignment of these interests. Pursuant to agreements reached between the parties in May and June 2013, Orca and the Company agreed to resolve all outstanding issues between the parties regarding the respective rights and obligations of the parties under the agreements between them. In addition, the Company agreed to bear 100% of the costs to drill, complete and equip the Cowey #3H and #4H wells. Until such time as the Company has recovered 100% of the costs to drill, complete and equip the wells, all revenues generated by production from these two wells will be attributable to the Company. Following the Company’s recovery of these amounts, Orca would participate in the wells for a 25% working interest. The Company has returned $8.7 million submitted by Orca’s putative assignee. The agreements also included a mutual release of claims between the Company and Orca and provided for the dismissal of the Bexar County litigation. Orca filed a notice of non-suit on August 7, 2013.
The Company is a defendant in several other lawsuits encountered in the ordinary course of its business. 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.
NOTE 10 - SUPPLEMENTAL DISCLOSURES
Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at June 30, 2013 and December 31, 2012 (in thousands).
 
 
June 30, 
 2013
 
December 31,
2012
Accrued evaluated and unproved and unevaluated property costs
$
38,297

 
$
45,592

Accrued support equipment and facilities costs
467

 
1,382

Accrued stock-based compensation

 
65

Accrued lease operating expenses
5,823

 
5,218

Accrued interest on borrowings under Credit Agreement
186

 
255

Accrued asset retirement obligations
804

 
660

Accrued partners’ share of joint interest charges
131

 
3,597

Other
2,804

 
2,410

Total accrued liabilities
$
48,512

 
$
59,179

 

24

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

NOTE 10 - SUPPLEMENTAL DISCLOSURES - Continued

Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the six months ended June 30, 2013 and 2012 (in thousands).
 
Six Months Ended 
 June 30,
 
2013
 
2012
Cash paid for interest expense, net of amounts capitalized
$
1,817

 
$
226

Asset retirement obligations related to mineral properties
751

 
293

Asset retirement obligations related to support equipment and facilities
4

 
33

(Decrease) increase in liabilities for oil and natural gas properties capital expenditures
(6,859
)
 
8,995

(Decrease) increase in liabilities for support equipment and facilities
(914
)
 
(215
)
(Decrease) increase in liabilities for accrued cost to issue equity

 
(331
)
Issuance of restricted stock units for Board and advisor services
87

 
10

Issuance of common stock for advisor services
17

 
61

Stock-based compensation expense recognized as liability
284

 
(491
)
Transfer of inventory from oil and natural gas properties
191

 

NOTE 11 - SUBSIDIARY GUARANTORS
Matador filed a registration statement on Form S-3 with the SEC, which became effective May 9, 2013, and registered, among other securities, debt securities. The subsidiaries of Matador (the “Subsidiaries”) are co-registrants with Matador, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of June 30, 2013, the Subsidiaries are 100 percent owned by Matador and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). Matador has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to Matador. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by Matador, such guarantees will constitute joint and several obligations.
 

25

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

NOTE 12 - SUBSEQUENT EVENTS
In July and August 2013, the Company acquired approximately 6,600 gross and 3,600 net acres prospective for the Wolfcamp and Bone Spring formations in Southeast New Mexico and West Texas. The Company paid approximately $7.6 million to acquire this acreage.




26


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 notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC (the “Annual Report”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and in conjunction with “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.
Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering.
For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the success of our drilling program, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this 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;

27


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 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
Matador Resources 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 a particular emphasis on oil and natural gas shale plays and other unconventional resource 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 Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The Company also has a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale.
Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows, reserves and borrowing base under our Credit Agreement.

During the first six months of 2013, our operations were focused primarily on the exploration and development of our Eagle Ford shale properties in South Texas. During the six months ended June 30, 2013, we completed and began producing oil and natural gas from 11 gross (11.0 net) operated and 2 gross (0.8 net) non-operated Eagle Ford shale wells. We also

28


participated in 5 gross (0.4 net) non-operated Haynesville shale wells in Northwest Louisiana and one non-operated test of the Buda formation in South Texas (approximately 21% working interest).

We had two contracted drilling rigs operating continuously during the six months ended June 30, 2013. During the first quarter of 2013, both of these rigs were operating in South Texas, and all of our operated drilling and completion activities were focused on the Eagle Ford shale. In late April 2013, we moved one of these contracted drilling rigs to Southeast New Mexico to begin a three-well exploration program testing portions of our leasehold position in the Delaware Basin in Southeast New Mexico and West Texas. As these are the first wells we are drilling in this area, we expect to collect additional well log, core and other petrophysical data on these initial test wells. As a result, these wells are expected to take longer to drill and complete and will cost more than we anticipate for subsequent wells once we begin development drilling in this area. At August 8, 2013, we were testing potential completion intervals in our first well (Ranger 12 State #1) and were drilling our second well (Ranger 33 State Com #1H) in Lea County, New Mexico. We had two contracted drilling rigs operating - one in Gonzales County, Texas and the other in Lea County, New Mexico. We expect to return to a two-rig program in the Eagle Ford shale in South Texas in late August 2013 and plan to operate three rigs for a short period of time during the third quarter while we complete drilling operations on our first well in Loving County, Texas.

During the three months ended June 30, 2013 specifically, we completed and began producing oil and natural gas from 7 gross (7.0 net) operated and 2 gross (0.8 net) non-operated Eagle Ford shale wells. We completed three operated Eagle Ford wells on our Cowey lease in DeWitt County, Texas and four wells on our Martin Ranch lease in northeast LaSalle County, Texas. We completed and began producing oil and natural gas from two non-operated Eagle Ford wells on our Troutt leasehold in central LaSalle County. We also participated in 3 gross (0.4 net) non-operated Haynesville shale wells in Northwest Louisiana. The two non-operated Troutt wells began producing in early May 2013, the three wells on the Cowey lease began producing in mid-May, and the four Martin Ranch wells began producing in early June 2013. As a result, these wells did not contribute fully to our second quarter production volumes. Furthermore, these seven operated wells were the first Eagle Ford wells we had placed on production since early February 2013. In addition, we shut in up to 20% of our total production at various times during the second quarter of 2013, averaging about 10% to 12% of total production capacity shut in during the quarter, as we continued our practice of shutting in offsetting producing wells while we completed and conducted fracturing operations on these new wells.

Our average daily oil equivalent production for the three months ended June 30, 2013 was 10,582 BOE per day, including 4,916 Bbl of oil per day and 34.0 MMcf of natural gas per day, an increase of 21%, as compared to 8,738 BOE per day, including 3,130 Bbl of oil per day and 33.6 MMcf of natural gas per day for the three months ended June 30, 2012. As noted above, due to our pad drilling operations and shutting in various producing wells, we had an average of approximately 10% to 12% of our total production capacity shut-in during the second quarter of 2013. As a result, our average daily oil equivalent production of 10,582 BOE per day decreased about 3% sequentially from an average daily oil equivalent production of approximately 10,900 BOE per day during the first quarter of 2013. Our average daily oil production of 4,916 Bbl of oil per day for the three months ended June 30, 2013 was an increase of 57% from an average daily oil production of 3,130 Bbl of oil per day for the three months ended June 30, 2012. This year-over-year increase in our average daily oil equivalent production and, in particular, our average daily oil production is directly attributable to our ongoing drilling operations in the Eagle Ford shale. Our average daily oil equivalent production for the six months ended June 30, 2013 was approximately 10,739 BOE per day, including 5,015 Bbl of oil per day and 34.3 MMcf of natural gas per day, an increase of 28%, as compared to 8,380 BOE per day, including 2,670 Bbl per day of oil and 34.3 MMcf of natural gas per day for the six months ended June 30, 2012. Our average daily oil production of 5,015 Bbl of oil per day for the six months ended June 30, 2013 was an increase of 88%, as compared to an average daily oil production of 2,670 Bbl per day during the first six months of 2012. Oil production comprised 46% and 47% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the three and six months ended June 30, 2013, respectively, as compared to approximately 36% and 32%, respectively, of our total production for the three and six months ended June 30, 2012. A step change in our production occurred during the second quarter of 2013. Our production averaged 4,825 Bbl of oil per day and 33.8 MMcf of natural gas per day in the first five months of 2013. Since June 1, 2013, however, most of the shut-in wells have been returned to production along with the recently competed wells, and, as a result, our exit production rate at June 30, 2013 was approximately 6,000 Bbl of oil per day. We averaged 6,200 Bbl of oil per day and 38.4 MMcf of natural gas per day during June and July 2013.

For the three months ended June 30, 2013, our oil and natural gas revenues were $58.2 million, an increase of 61% from oil and natural gas revenues of $36.1 million for the three months ended June 30, 2012. Our oil revenues increased 52% to $44.6 million during the second quarter of 2013, as compared to oil revenues of $29.4 million during the second quarter of 2012. This increase reflects our increase in oil production of 57% during the three months ended June 30, 2013, as compared to the three months ended June 30, 2012. Our natural gas revenues more than doubled to $13.5 million for the three months ended June 30, 2013, as compared to natural gas revenues of $6.7 million during the three months ended June 30, 2012. This increase

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in natural gas revenues was primarily due to a doubling in the natural gas prices we realized between these periods to $4.38 per Mcf during the second quarter of 2013 from $2.17 per Mcf during the second quarter of 2012. For the six months ended June 30, 2013, our oil and natural gas revenues were $117.5 million, an increase of 80% from oil and natural gas revenues of $65.2 million for the six months ended June 30, 2012. Our oil revenues increased 83% to $93.3 million during the first six months of 2013, as compared to oil revenues of $51.0 million for the first six months of 2012. Our natural gas revenues increased 70% to $24.2 million for the six months ended June 30, 2013, as compared to natural gas revenues of $14.3 million for the six months ended June 30, 2012. Our oil and natural gas revenues of $117.5 million for the six months ended June 30, 2013 increased 29% compared to $90.8 million for the six months ended December 31, 2012. For the three months ended June 30, 2013, our Adjusted EBITDA was $40.8 million, an increase of 46% from an Adjusted EBITDA of $27.9 million reported for the three months ended June 30, 2012, and slightly higher than an Adjusted EBITDA of $40.7 million reported for the first quarter of 2013. Our Adjusted EBITDA for the six months ended June 30, 2013 was $81.4 million, an increase of 65% from an Adjusted EBITDA of $49.3 million reported for the six months ended June 30, 2012. Our Adjusted EBITDA of $81.4 million for the six months ended June 30, 2013 increased 22% sequentially, as compared to $66.7 million for the six months ended December 31, 2012.

We realized a weighted average oil price of $99.77 per Bbl for the three months ended June 30, 2013, as compared to $103.29 per Bbl for the three months ended June 30, 2012 and $105.72 per Bbl during the first quarter of 2013. This weighted average oil price of $99.77 per Bbl represented an uplift of about $9 per Bbl compared to NYMEX West Texas Intermediate oil prices during the second quarter of 2013, as compared to an uplift of $10 to $12 per Bbl during the first quarter of 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. During the second quarter of 2013, the differential between Louisiana Light Sweet and West Texas Intermediate oil prices narrowed as compared to the first quarter of 2013, and subsequent to June 30, 2013, the price differential between these two benchmark prices has continued to narrow. As a result, we may not realize similar uplifts to West Texas Intermediate oil prices in future periods.