10-Q 1 mtdr-2016930x10q.htm 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 _________________________________________________________ 
FORM 10-Q
 _________________________________________________________  
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-35410
 _________________________________________________________  
Matador Resources Company
(Exact name of registrant as specified in its charter)
  _________________________________________________________ 
 
Texas
27-4662601
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
5400 LBJ Freeway, Suite 1500
Dallas, Texas
75240
(Address of principal executive offices)
(Zip Code)
(972) 371-5200
(Registrant’s telephone number, including area code)
 _________________________________________________________  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     x  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
x
 
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
 
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No
As of November 1, 2016, there were 93,469,313 shares of the registrant’s common stock, par value $0.01 per share, outstanding.



MATADOR RESOURCES COMPANY
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2016
INDEX
 
Page



Part I – FINANCIAL INFORMATION
Item 1. Financial Statements — Unaudited

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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED
(In thousands, except par value and share data)
 
September 30,
2016
 
December 31,
2015
ASSETS
 
 
 
Current assets
 
 
 
Cash
$
20,566

 
$
16,732

Restricted cash
1,803

 
44,357

Accounts receivable
 
 
 
Oil and natural gas revenues
27,739

 
16,616

Joint interest billings
18,796

 
16,999

Other
5,657

 
10,794

Derivative instruments

 
16,284

Lease and well equipment inventory
3,182

 
2,022

Prepaid expenses
3,277

 
3,203

Total current assets
81,020

 
127,007

Property and equipment, at cost
 
 
 
Oil and natural gas properties, full-cost method
 
 
 
Evaluated
2,341,342

 
2,122,174

Unproved and unevaluated
445,421

 
387,504

Other property and equipment
141,420

 
86,387

Less accumulated depletion, depreciation and amortization
(1,832,478
)
 
(1,583,659
)
Net property and equipment
1,095,705

 
1,012,406

Other assets
968

 
1,448

Total assets
$
1,177,693

 
$
1,140,861

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
4,534

 
$
10,966

Accrued liabilities
93,339

 
92,369

Royalties payable
21,717

 
16,493

Amounts due to affiliates
7,033

 
5,670

Derivative instruments
10,139

 

Advances from joint interest owners
3,847

 
700

Deferred gain on plant sale
6,440

 
4,830

Amounts due to joint ventures
4,050

 
2,793

Income taxes payable

 
2,848

Other current liabilities
530

 
161

Total current liabilities
151,629

 
136,830

Long-term liabilities
 
 
 
Borrowings under Credit Agreement
65,000

 

Senior unsecured notes payable
392,153

 
391,254

Asset retirement obligations
19,452

 
15,166

Amounts due to joint ventures
2,700

 
3,956

Derivative instruments
3,838

 

Deferred gain on plant sale
97,676

 
102,506

Other long-term liabilities
7,451

 
2,190

Total long-term liabilities
588,270

 
515,072

Commitments and contingencies (Note 10)


 


Shareholders’ equity
 
 
 
Common stock - $0.01 par value, 120,000,000 shares authorized; 93,580,969 and 85,567,021 shares issued; and 93,464,898 and 85,564,435 shares outstanding, respectively
936

 
856

Additional paid-in capital
1,176,198

 
1,026,077

Retained deficit
(740,505
)
 
(538,930
)
Total Matador Resources Company shareholders’ equity
436,629

 
488,003

Non-controlling interest in subsidiaries
1,165

 
956

Total shareholders’ equity
437,794

 
488,959

Total liabilities and shareholders’ equity
$
1,177,693

 
$
1,140,861


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED
(In thousands, except per share data)
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2016
 
2015
 
2016
 
2015
Revenues
 
 
 
 
 
 
 
Oil and natural gas revenues
$
83,079

 
$
71,815

 
$
196,341

 
$
222,128

Third-party midstream services revenues
1,566

 
569

 
2,956

 
1,384

Realized gain on derivatives
885

 
19,862

 
10,413

 
52,146

Unrealized gain (loss) on derivatives
3,203

 
6,733

 
(30,261
)
 
(25,356
)
Total revenues
88,733

 
98,979

 
179,449

 
250,302

Expenses
 
 
 
 
 
 
 
Production taxes, transportation and processing
12,388

 
9,426

 
30,846

 
26,734

Lease operating
14,605

 
13,466

 
41,300

 
40,140

Plant and other midstream services operating
1,449

 
1,450

 
3,537

 
2,772

Depletion, depreciation and amortization
30,015

 
45,237

 
90,185

 
143,477

Accretion of asset retirement obligations
276

 
182

 
828

 
427

Full-cost ceiling impairment

 
285,721

 
158,633

 
581,874

General and administrative
13,146

 
12,151

 
39,506

 
38,523

Total expenses
71,879

 
367,633

 
364,835

 
833,947

Operating income (loss)
16,854

 
(268,654
)
 
(185,386
)
 
(583,645
)
Other income (expense)
 
 
 
 
 
 
 
Net gain (loss) on asset sales and inventory impairment
1,073

 

 
3,140

 
(97
)
Interest expense
(6,880
)
 
(7,229
)
 
(20,244
)
 
(15,168
)
Other (expense) income
(141
)
 
564

 
(17
)
 
637

Total other expense
(5,948
)
 
(6,665
)
 
(17,121
)
 
(14,628
)
Income (loss) before income taxes
10,906

 
(275,319
)
 
(202,507
)
 
(598,273
)
Income tax (benefit) provision
 
 
 
 
 
 
 
Current
(1,141
)
 
(295
)
 
(1,141
)
 
(295
)
Deferred

 
(33,010
)
 

 
(148,750
)
Total income tax benefit
(1,141
)
 
(33,305
)
 
(1,141
)
 
(149,045
)
Net income (loss)
12,047

 
(242,014
)
 
(201,366
)
 
(449,228
)
Net income attributable to non-controlling interest in subsidiaries
(116
)
 
(45
)
 
(209
)
 
(156
)
Net income (loss) attributable to Matador Resources Company shareholders
$
11,931

 
$
(242,059
)
 
$
(201,575
)
 
$
(449,384
)
Earnings (loss) per common share
 
 
 
 

 

Basic
$
0.13

 
$
(2.86
)
 
$
(2.24
)
 
$
(5.58
)
Diluted
$
0.13

 
$
(2.86
)
 
$
(2.24
)
 
$
(5.58
)
Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
93,384

 
84,685

 
90,016

 
80,481

Diluted
93,724

 
84,685

 
90,016

 
80,481


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY - UNAUDITED
(In thousands)
For the Nine Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
Total shareholders’ equity attributable to Matador Resources Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-controlling interest in subsidiary
 
Total shareholders’ equity
 
Common Stock
 
Additional
paid-in capital
 
Retained deficit
 
Treasury Stock
 
 
 
 
Shares
 
Amount
 
 
 
Shares
 
Amount
 
 
 
Balance at January 1, 2016
85,567

 
$
856

 
$
1,026,077

 
$
(538,930
)
 
2

 
$

 
$
488,003

 
$
956

 
$
488,959

Issuance of common stock
7,500

 
75

 
142,275

 

 

 

 
142,350

 

 
142,350

Cost to issue equity

 

 
(830
)
 

 

 

 
(830
)
 

 
(830
)
Stock-based compensation expense related to equity-based awards

 

 
8,681

 

 

 

 
8,681

 

 
8,681

Stock options exercised, net of options forfeited in net share settlements
18

 

 

 

 

 

 

 

 

Restricted stock issued
465

 
5

 
(5
)
 

 

 

 

 

 

Restricted stock forfeited

 

 

 

 
114

 

 

 

 

Vesting of restricted stock units
31

 

 

 

 

 

 

 

 

Current period net loss

 

 

 
(201,575
)
 

 

 
(201,575
)
 
209

 
(201,366
)
Balance at September 30, 2016
93,581

 
$
936

 
$
1,176,198

 
$
(740,505
)
 
116

 
$

 
$
436,629

 
$
1,165

 
$
437,794


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


Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED
(In thousands)
 
Nine Months Ended 
 September 30,
 
2016
 
2015
Operating activities
 
 
 
Net loss
$
(201,366
)
 
$
(449,228
)
Adjustments to reconcile net loss to net cash provided by operating activities
 
 
 
Unrealized loss on derivatives
30,261

 
25,356

Depletion, depreciation and amortization
90,185

 
143,477

Accretion of asset retirement obligations
828

 
427

Full-cost ceiling impairment
158,633

 
581,874

Stock-based compensation expense
9,138

 
6,886

Deferred income tax benefit

 
(148,750
)
Amortization of debt issuance cost
899

 
551

Net (gain) loss on asset sales and inventory impairment
(3,140
)
 
97

Changes in operating assets and liabilities

 

Accounts receivable
(7,782
)
 
1,997

Lease and well equipment inventory
(669
)
 
(225
)
Prepaid expenses
(74
)
 
(329
)
Other assets
480

 
665

Accounts payable, accrued liabilities and other current liabilities
9,710

 
16,863

Royalties payable
5,225

 
6,898

Advances from joint interest owners
3,147

 
306

Income taxes payable
(2,848
)
 
(444
)
Other long-term liabilities
3,835

 
(497
)
Net cash provided by operating activities
96,462

 
185,924

Investing activities


 


Oil and natural gas properties capital expenditures
(288,175
)
 
(334,951
)
Expenditures for other property and equipment
(57,148
)
 
(46,738
)
Proceeds from sale of assets
5,173

 

Business combination, net of cash acquired

 
(24,028
)
Restricted cash
43,098

 

Restricted cash in less-than-wholly-owned subsidiaries
(544
)
 
158

Net cash used in investing activities
(297,596
)
 
(405,559
)
Financing activities


 


Repayments of borrowings

 
(476,982
)
Borrowings under Credit Agreement
65,000

 
125,000

Proceeds from issuance of senior unsecured notes

 
400,000

Cost to issue senior unsecured notes

 
(9,479
)
Proceeds from issuance of common stock
142,350

 
188,720

Cost to issue equity
(830
)
 
(1,151
)
Proceeds from stock options exercised

 
10

Capital commitments from non-controlling interest owners in less-than-wholly-owned subsidiaries

 
562

Taxes paid related to net share settlement of stock-based compensation
(1,552
)
 
(1,565
)
Net cash provided by financing activities
204,968

 
225,115

Increase in cash
3,834

 
5,480

Cash at beginning of period
16,732

 
8,407

Cash at end of period
$
20,566

 
$
13,887

 
 
 
 
Supplemental disclosures of cash flow information (Note 11)


 



The accompanying notes are an integral part of these financial statements.
7


Matador Resources Company and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -
UNAUDITED
NOTE 1 - NATURE OF OPERATIONS
Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations in support of its exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates
The interim 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, 2015 (the “Annual Report”) filed with the SEC. The Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. In management’s opinion, these interim unaudited condensed consolidated financial statements include all adjustments, consisting only of normal, recurring adjustments, which are necessary for a fair presentation of the Company’s interim unaudited condensed consolidated financial statements as of September 30, 2016. Amounts as of December 31, 2015 are derived from the Company’s audited consolidated financial statements in the Annual Report.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s interim unaudited condensed consolidated financial statements are based on a number of significant estimates, including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil and natural gas operations, stock-based compensation, valuation of derivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
Reclassifications
Certain reclassifications have been made to the prior periods’ financial statements to conform to the current period presentation. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting at September 30, 2016. As a result, $0.5 million and $1.3 million for the three and nine months ended September 30, 2015, respectively, were reclassified from other income to third-party midstream services revenues and $0.1 million for both the three and nine months ended September 30, 2015 was reclassified from production taxes, transportation and processing expenses to third-party midstream services revenues. In addition, $1.5 million and $2.8 million related to midstream operating costs for the three and nine months ended September 30, 2015, respectively, were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.
Change in Accounting Principle
During the second quarter of 2016, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718), which simplifies several aspects of the accounting for employee share-based payment transactions, including accounting for income tax, forfeitures, statutory tax withholding requirements, classifications of awards as either equity or liability and classification of taxes in the statement of cash flows, requiring either retrospective, modified retrospective or prospective transition. The amended guidance also requires an entity to record excess tax benefits and

8

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

deficiencies in the income statement. The adoption of this ASU had no impact on any period presented for (i) the Company’s financial position or statements of operations, as the Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of cash flows, as the Company has historically accounted for taxes paid for net share settlement as a financing activity as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of this ASU.
Property and Equipment
The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the capitalized costs of oil and natural gas properties based primarily on the after-tax estimated future net cash flows from oil and natural gas properties using a 10% discount rate and the arithmetic average of first-day-of-the-month oil and natural gas prices for the prior 12-month period. For the three months ended September 30, 2016, the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, thus no impairment charge was necessary; however, due primarily to declines in oil and natural gas prices in recent periods, the capitalized costs of oil and natural gas properties exceeded the cost center ceiling for the first two quarters of 2016 and all of 2015, and as a result, the Company recorded impairment charges to its net capitalized costs in its unaudited condensed consolidated statements of operations of $285.7 million for the three months ended September 30, 2015, and $158.6 million and $581.9 million for the nine months ended September 30, 2016 and 2015, respectively.
The Company capitalized approximately $4.3 million and $1.4 million of its general and administrative costs for the three months ended September 30, 2016 and 2015, respectively, and approximately $0.7 million and $0.5 million of its interest expense for the three months ended September 30, 2016 and 2015, respectively. The Company capitalized approximately $10.3 million and $4.9 million of its general and administrative costs for the nine months ended September 30, 2016 and 2015, respectively, and approximately $2.9 million of its interest expense for each of the nine months ended September 30, 2016 and 2015.
Earnings (Loss) Per Common Share
The Company reports basic earnings (loss) per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive.
The following table sets forth the computation of diluted weighted average common shares outstanding for the three and nine months ended September 30, 2016 and 2015 (in thousands).
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
2016
 
2015
 
2016
 
2015
Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
93,384

 
84,685

 
90,016

 
80,481

Dilutive effect of options, restricted stock units and preferred shares
340

 

 

 

Diluted weighted average common shares outstanding
93,724

 
84,685

 
90,016

 
80,481

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the diluted weighted average common shares outstanding for the nine months ended September 30, 2016, because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the nine months ended September 30, 2016, as the security holders do not have the obligation to share in the losses of the Company.
A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the diluted weighted average common shares outstanding for both the three and nine months ended September 30, 2015, respectively, and zero and 1.5 million preferred shares were excluded from the calculations above for both the three and nine months ended September 30, 2015, respectively, because their effects were anti-dilutive. Additionally, 0.8 million restricted shares, which are participating securities, were excluded from the calculations above for both the three and

9

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued

nine months ended September 30, 2015, respectively, as the security holders do not have the obligation to share in the losses of the Company.
Recent Accounting Pronouncements
Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. In addition, this standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. This ASU will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted for periods beginning after December 15, 2016. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements.
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.
NOTE 3 - EQUITY
On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million, the Company received net proceeds of approximately $141.5 million, which were used for general corporate purposes, including to fund a portion of the Company’s 2016 capital expenditures.
NOTE 4 - ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations for the nine months ended September 30, 2016 (in thousands).
 
 
Beginning asset retirement obligations
$
15,420

Liabilities incurred during period
1,903

Liabilities settled during period
(317
)
Revisions in estimated cash flows
1,647

Accretion expense
828

Ending asset retirement obligations
19,481

Less: current asset retirement obligations(1)
(29
)
Long-term asset retirement obligations
$
19,452

 _______________
(1)
Included in accrued liabilities in the Company’s interim unaudited condensed consolidated balance sheet at September 30, 2016.
NOTE 5 - DEBT
At September 30, 2016, the Company had $400 million of outstanding 6.875% senior notes due 2023 (the “Notes”), $65.0 million in borrowings outstanding under the Company’s revolving credit agreement (the “Credit Agreement”) and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. At November 1, 2016, the Company had $400.0 million in Notes outstanding, $95.0 million in borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

10

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

NOTE 5 - DEBT - Continued

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves 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. On May 3, 2016, the borrowing base under the Credit Agreement was reduced to $300.0 million from $375.0 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at December 31, 2015. At September 30, 2016, the borrowing base under the Credit Agreement remained $300.0 million. During the fourth quarter of 2016, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at June 30, 2016, and as a result, in late October 2016, the borrowing base under the Credit Agreement was increased to $400.0 million. This October 2016 redetermination constituted the regularly scheduled November 1 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 of the 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.
The Company believes that it was in compliance with the terms of the Credit Agreement at September 30, 2016.
On April 14, 2015, the Company issued the Notes, which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At September 30, 2016, all of the Guarantor Subsidiaries are 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries are minor. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan.
NOTE 6 - INCOME TAXES
The Company’s deferred tax assets exceed its deferred tax liabilities due to the deferred tax assets generated by the full-cost ceiling impairment charges recorded in prior periods; as a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015. The Company retains a full valuation allowance at September 30, 2016 due to uncertainties regarding the future realization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized. The current tax benefit for the three and nine months ended September 30, 2016 represents a refund due from the Internal Revenue Service for 2015 income taxes.
The total income tax benefit for the three and nine months ended September 30, 2015 differed from amounts computed by applying the U.S. federal statutory tax rate to loss before income taxes due primarily to the recording of the valuation allowance against the net deferred tax assets, which resulted from the full-cost ceiling impairment recorded in the third quarter of 2015.
NOTE 7 - STOCK-BASED COMPENSATION
In February 2016, the Company granted awards of 243,428 shares of restricted stock and options to purchase 608,287 shares of the Company’s common stock at an exercise price of $15.00 per share to certain of its employees. The fair value of these awards was approximately $7.0 million. All of these awards vest on the three-year anniversary of the grant date of these awards. In August 2016, the Company granted awards of 177,024 shares of restricted stock and options to purchase 39,903 shares of the Company’s common stock at an exercise price of $22.70 per share to certain of its employees. The fair value of these awards was $4.3 million. All of these awards vest ratably over three years.
NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS
At September 30, 2016, 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 2016 and 2017.

11

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at September 30, 2016.
Commodity
Calculation Period
 
Notional Quantity (Bbl or MMBtu)
 
Weighted Average Price Floor ($/Bbl or
$/MMBtu)
 
Weighted Average Price Ceiling ($/Bbl or
$/MMBtu)
 
Fair Value of Asset (Liability) (thousands)
Oil
10/01/2016 - 12/31/2016
 
690,000

 
$
42.48

 
$
61.16

 
$
(788
)
Oil
01/01/2017 - 12/31/2017
 
2,160,000

 
$
39.56

 
$
50.36

 
(11,097
)
Natural Gas
10/01/2016 - 12/31/2016
 
4,660,000

 
$
2.65

 
$
3.68

 
(43
)
Natural Gas
01/01/2017 - 12/31/2017
 
16,860,000

 
$
2.40

 
$
3.59

 
(2,049
)
Total open derivative financial instruments
 
 
 
 
 
 
 
$
(13,977
)
These derivative financial instruments are subject to master netting arrangements; all but one counterparty 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 interim unaudited condensed consolidated balance sheets.

12

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

NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS - Continued

 The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the interim unaudited condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015 (in thousands).
Derivative Instruments
Gross
amounts
recognized
 
Gross amounts
netted in the condensed
consolidated
balance sheets
 
Net amounts presented in the condensed
consolidated
balance sheets
September 30, 2016
 
 
 
 
 
   Current assets
$
3,498

 
$
(3,498
)
 
$

   Other assets
1,512

 
(1,512
)
 

   Current liabilities
(13,637
)
 
3,498

 
(10,139
)
   Other liabilities
(5,350
)
 
1,512

 
(3,838
)
      Total
$
(13,977
)
 
$

 
$
(13,977
)
December 31, 2015
 
 
 
 
 
   Current assets
$
16,767

 
$
(483
)
 
$
16,284

   Current liabilities
(483
)
 
483

 

      Total
$
16,284

 
$

 
$
16,284

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the interim unaudited condensed consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Type of Instrument
Location in Condensed Consolidated Statement of Operations
 
2016
 
2015
 
2016
 
2015
Derivative Instrument
 
 
 
 
 
 
 
 
 
Oil
Revenues: Realized gain on derivatives
 
$
837

 
$
17,056

 
$
6,861

 
$
42,013

Natural Gas
Revenues: Realized gain on derivatives
 
48

 
2,215

 
3,552

 
8,531

Natural Gas Liquids
Revenues: Realized gain on derivatives
 

 
591

 

 
1,602

Realized gain on derivatives
 
885

 
19,862

 
10,413

 
52,146

Oil
Revenues: Unrealized gain (loss) on derivatives
 
2,007

 
6,421

 
(24,967
)
 
(19,923
)
Natural Gas
Revenues: Unrealized gain (loss) on derivatives
 
1,196

 
808

 
(5,294
)
 
(4,035
)
Natural Gas Liquids
Revenues: Unrealized loss on derivatives
 

 
(496
)
 

 
(1,398
)
Unrealized gain (loss) on derivatives
 
3,203

 
6,733

 
(30,261
)
 
(25,356
)
Total
 
 
$
4,088

 
$
26,595

 
$
(19,848
)
 
$
26,790

NOTE 9 - FAIR VALUE MEASUREMENTS
The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories in the fair value hierarchy:
Level 1
Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

13

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

NOTE 9 - FAIR VALUE MEASUREMENTS - Continued

Level 2
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3
Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions.
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.
The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of September 30, 2016 and December 31, 2015 (in thousands). 
 
Fair Value Measurements at
September 30, 2016 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Liabilities
 
 
 
 
 
 
 
Oil and natural gas derivatives
$

 
$
(13,977
)
 
$

 
$
(13,977
)
Total
$

 
$
(13,977
)
 
$

 
$
(13,977
)
 
Fair Value Measurements at
December 31, 2015 using
Description
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
   Oil and natural gas derivatives
$

 
$
16,284

 
$

 
$
16,284

           Total
$

 
$
16,284

 
$

 
$
16,284

Additional disclosures related to derivative financial instruments are provided in Note 8.
Other Fair Value Measurements
At September 30, 2016 and December 31, 2015, the carrying values reported on the interim unaudited condensed consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures, income taxes payable and other current liabilities approximated their fair values due to their short-term maturities.
At September 30, 2016, the carrying value of borrowings under the Credit Agreement approximated its 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.
At September 30, 2016 and December 31, 2015, the fair value of the Notes was $413.1 million and $381.0 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.


14

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

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Natural Gas and NGL Processing and Transportation Commitments
Effective September 1, 2012, the Company entered into a firm five-year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees payable by the Company, and the revenue the Company receives for the residue natural gas varies with the quality of natural gas transported to the processing facilities and the contract period.
Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company’s remaining aggregate undiscounted minimum commitments under this agreement are $1.6 million at September 30, 2016. The Company paid $0.7 million and $1.6 million in processing and transportation fees under this agreement during the three months ended September 30, 2016 and 2015, respectively, and $2.4 million and $4.3 million in processing and transportation fees under this agreement during the nine months ended September 30, 2016 and 2015, respectively.
In late 2015, the Company entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage through the counterparty’s gathering system for processing at the counterparty’s facility. Under this agreement, if the Company does not meet the volume commitment for gathering and processing at the facility in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual gathering and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at September 30, 2016, the total deficiency fee required to be paid would be approximately $12.0 million. In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $2.4 million in processing and gathering fees under this agreement during the three months ended September 30, 2016 and $7.1 million during the nine months ended September 30, 2016. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plant.
Other Commitments
The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for one year or less, although the Company has entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were until recently experiencing heavy demand for drilling rigs. The Company would incur a termination obligation if the Company elected to terminate a contract and the drilling contractor were unable to secure work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $43.0 million at September 30, 2016.
The Company entered into an agreement in late 2015 with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in the Rustler Breaks asset area in Eddy County, New Mexico. The plant was completed in the third quarter of 2016 and currently processes a portion of the Company’s natural gas produced from certain of its wells in the Delaware Basin. At September 30, 2016, total remaining commitments under this contract were $4.2 million, and the Company made payments totaling $1.4 million during the three months ended September 30, 2016 and $19.2 million during the nine months ended September 30, 2016.

15

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

NOTE 10 - COMMITMENTS AND CONTINGENCIES - Continued

At September 30, 2016, the Company had agreed to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed, the Company will have undiscounted minimum outstanding aggregate commitments for its participation in these wells of approximately $11.2 million at September 30, 2016, which the Company expects to incur within the next few months.
Legal Proceedings
The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.
NOTE 11 - SUPPLEMENTAL DISCLOSURES
Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at September 30, 2016 and December 31, 2015 (in thousands).
 
September 30,
2016
 
December 31, 2015
Accrued evaluated and unproved and unevaluated property costs
$
44,551

 
$
54,586

Accrued support equipment and facilities costs
14,990

 
17,393

Accrued lease operating expenses
13,097

 
7,743

Accrued interest on debt
12,741

 
5,806

Accrued asset retirement obligations
29

 
254

Accrued partners’ share of joint interest charges
5,646

 
4,565

Other
2,285

 
2,022

Total accrued liabilities
$
93,339

 
$
92,369

Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the nine months ended September 30, 2016 and 2015 (in thousands).
 
Nine Months Ended 
 September 30,
 
2016
 
2015
Cash paid for interest expense, net of amounts capitalized
$
13,370

 
$
2,617

Asset retirement obligations related to mineral properties
$
2,588

 
$
1,487

Asset retirement obligations related to support equipment and facilities
$
644

 
$
89

Decrease in liabilities for oil and natural gas properties capital expenditures
$
(7,849
)
 
$
(30,282
)
(Decrease) increase in liabilities for support equipment and facilities
$
(2,687
)
 
$
2,525

Stock-based compensation expense recognized as liability
$
457

 
$
191

Transfer of inventory from oil and natural gas properties
$
655

 
$
586


16

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

NOTE 12 - SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.
The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues primarily consist of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses.
 
Exploration and Production
 
 
 
 
 
 
 
Consolidated Company
 
 
Midstream
 
Corporate
 
Eliminations
 
Three Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Oil and natural gas revenues
$
82,794

 
$
285

 
$

 
$

 
$
83,079

Midstream services revenues

 
5,609

 

 
(4,043
)
 
1,566

Realized gain on derivatives
885

 

 

 

 
885

Unrealized gain on derivatives
3,203

 

 

 

 
3,203

Expenses (1)
60,222

 
2,277

 
13,423

 
(4,043
)
 
71,879

Operating income (loss) (2)
$
26,660

 
$
3,617

 
$
(13,423
)
 
$

 
$
16,854

Total Assets
$
1,020,648

 
$
124,153

 
$
32,892

 
$

 
$
1,177,693

Capital Expenditures
$
116,279

 
$
17,370

 
$
1,903

 
$

 
$
135,552

_____________________
(1) Expenses include depreciation, depletion and amortization expenses of $28.9 million, $0.8 million and $0.3 million for the exploration and production, midstream and corporate segments, respectively.
(2) Includes $116,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

17

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

NOTE 12 - SEGMENT INFORMATION - Continued


 
Exploration and Production
 
 
 
 
 
 
 
Consolidated Company
 
 
Midstream
 
Corporate
 
Eliminations
 
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Oil and natural gas revenues
$
71,665

 
$
150

 
$

 
$

 
$
71,815

Midstream services revenues

 
3,886

 

 
(3,317
)
 
569

Realized gain on derivatives
19,862

 

 

 

 
19,862

Unrealized gain on derivatives
6,733

 

 

 

 
6,733

Expenses (1)
356,762

 
1,964

 
12,224

 
(3,317
)
 
367,633

Operating (loss) income (2)
$
(258,502
)
 
$
2,072

 
$
(12,224
)
 
$

 
$
(268,654
)
Total Assets
$
1,169,283

 
$
83,089

 
$
28,150

 
$

 
$
1,280,522

Capital Expenditures
$
77,990

 
$
12,219

 
$
315

 
$

 
$
90,524

_____________________
(1) Expenses include depreciation, depletion and amortization expenses of $44.6 million, $0.5 million and $0.1 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $285.7 million for the exploration and production segment.
(2) Includes $45,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
 
Exploration and Production
 
 
 
 
 
 
 
Consolidated Company
 
 
Midstream
 
Corporate
 
Eliminations
 
Nine Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Oil and natural gas revenues
$
195,467

 
$
874

 
$

 
$

 
$
196,341

Midstream services revenues

 
11,168

 

 
(8,212
)
 
2,956

Realized gain on derivatives
10,413

 

 

 

 
10,413

Unrealized loss on derivatives
(30,261
)
 

 

 

 
(30,261
)
Expenses (1)
327,585

 
5,373

 
40,089

 
(8,212
)
 
364,835

Operating (loss) income (2)
$
(151,966
)
 
$
6,669

 
$
(40,089
)
 
$

 
$
(185,386
)
Total Assets
$
1,020,648

 
$
124,153

 
$
32,892

 
$

 
$
1,177,693

Capital Expenditures
$
278,396

 
$
49,620

 
$
5,485

 
$

 
$
333,501

_____________________
(1) Expenses include depreciation, depletion and amortization expenses of $87.9 million, $1.7 million and $0.6 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment.
(2) Includes $209,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

18

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

NOTE 12 - SEGMENT INFORMATION - Continued


 
Exploration and Production
 
 
 
 
 
 
 
Consolidated Company
 
 
Midstream
 
Corporate
 
Eliminations
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Oil and natural gas revenues
$
221,768

 
$
360

 
$

 
$

 
$
222,128

Midstream services revenues

 
8,294

 

 
(6,910
)
 
1,384

Realized gain on derivatives
52,146

 

 

 

 
52,146

Unrealized loss on derivatives
(25,356
)
 

 

 

 
(25,356
)
Expenses (1)
798,044

 
3,990

 
38,823

 
(6,910
)
 
833,947

Operating (loss) income (2)
$
(549,486
)
 
$
4,664

 
$
(38,823
)
 
$

 
$
(583,645
)
Total Assets
$
1,169,283

 
$
83,089

 
$
28,150

 
$

 
$
1,280,522

Capital Expenditures
$
307,896

 
$
47,804

 
$
394

 
$

 
$
356,094

_____________________
(1) Expenses include depreciation, depletion and amortization expenses of $142.0 million, $1.2 million and $0.3 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $581.9 million for the exploration and production segment.
(2) Includes $156,000 in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

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 interim unaudited condensed consolidated financial statements and related notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (the “Quarterly Report”), references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole and references to “Matador” refer solely to Matador Resources Company.
For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words, although not all forward- looking statements contain such identifying 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: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, sufficient cash flow from operations together with available borrowing capacity under our credit agreement,

19


uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions, including the integration of Harvey E. Yates Company, with our business, weather and environmental conditions, 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;
our ability to negotiate and consummate acquisition and divestiture opportunities;
government regulation and taxation of the oil and natural gas industry;
our marketing of oil and natural gas;
our exploitation projects or property acquisitions;
the integration of acquisitions, including the integration of Harvey E. Yates Company, with our business;
our ability to construct and operate midstream facilities;
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; and
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
Overview
We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis.

20


Third Quarter and Year-to-Date Highlights
Quarterly oil, natural gas and oil equivalent production results for the third quarter of 2016 were the best in our history. For the three months ended September 30, 2016, our total oil equivalent production was 2.70 million BOE, and our average daily oil equivalent production was 29,381 BOE per day, of which 14,960 Bbl per day, or 51%, was oil and 86.5 MMcf per day, or 49%, was natural gas. Our oil production of 1.38 million Bbl for the three months ended September 30, 2016 increased 19% year-over-year from 1.16 million Bbl for the three months ended September 30, 2015. Our natural gas production of 8.0 Bcf for the three months ended September 30, 2016 increased 7% year-over-year from 7.5 Bcf for the three months ended September 30, 2015.
For the nine months ended September 30, 2016, our total oil equivalent production was 7.42 million BOE and our average daily oil equivalent production was 27,091 BOE per day, of which 13,322 Bbl per day, or 49%, was oil and 82.6 MMcf per day, or 51%, was natural gas. Our total oil equivalent production of 7.42 million BOE for the nine months ended September 30, 2016 increased 7% year-over-year from 6.94 million BOE for the nine months ended September 30, 2015. Our oil production of 3.65 million Bbl for the nine months ended September 30, 2016 increased 6% year-over-year from 3.43 million Bbl for the nine months ended September 30, 2015. Our natural gas production of 22.6 Bcf for the nine months ended September 30, 2016 increased 7% year-over-year from 21.1 Bcf for the nine months ended September 30, 2015.
During the third quarter of 2016, our oil and natural gas revenues were $83.1 million, an increase of 16% from oil and natural gas revenues of $71.8 million during the third quarter of 2015. The increase in our oil and natural gas revenues was due to (i) the 19% increase in our oil production to 1.38 million Bbl in the third quarter of 2016, as compared to 1.16 million Bbl produced in the third quarter of 2015 and (ii) the 7% increase in our natural gas production to 8.0 Bcf in the third quarter of 2016, as compared to 7.5 Bcf produced in the third quarter of 2015. The increase in oil and natural gas production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our activity since late 2014 and early 2015. This increase in oil and natural gas revenues was also partly attributable to the increase in the weighted average natural gas price to $3.08 per Mcf realized in the third quarter of 2016, as compared to the weighted average natural gas price of $2.90 per Mcf realized in the third quarter of 2015.
For the third quarter of 2016, we reported net income of approximately $11.9 million, or $0.13 per diluted common share on a GAAP basis, as compared to a net loss of $242.1 million, or $(2.86) per diluted common share, for the third quarter of 2015. For the third quarter of 2016, our Adjusted EBITDA, a non-GAAP financial measure, was $47.3 million, a decrease of 19% from Adjusted EBITDA of $58.0 million during the third quarter of 2015. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for 2016, see “— Results of Operations” below.
For the nine months ended September 30, 2016, our oil and natural gas revenues were $196.3 million, a decrease of 12% from oil and natural gas revenues of $222.1 million for the nine months ended September 30, 2015. This decrease was attributable to a sharp decline in the weighted average oil and natural gas prices to $38.75 per Bbl and $2.43 per Mcf, respectively, realized in the nine months ended September 30, 2016 from weighted average oil and natural gas prices of $47.36 per Bbl and $2.83 per Mcf, respectively, realized in the nine months ended September 30, 2015. The decrease in our oil and natural gas revenues was mitigated by the 6% increase in our oil production to 3.65 million Bbl for the nine months ended September 30, 2016, as compared to 3.43 million Bbl produced for the nine months ended September 30, 2015, and by the 7% increase in our natural gas production to 22.6 Bcf for the nine months ended September 30, 2016, as compared to 21.1 Bcf for the nine months ended September 30, 2015. This increase in oil and natural gas production was attributable to the same operations noted above for the third quarter of 2016.
For the nine months ended September 30, 2016, we reported a net loss of approximately $201.6 million, or $(2.24) per diluted common share on a GAAP basis, a decrease of 55%, as compared to a net loss of $449.4 million, or $(5.58) per diluted common share, for the nine months ended September 30, 2015. For the nine months ended September 30, 2016, our Adjusted EBITDA was $103.4 million, a decrease of 41% from Adjusted EBITDA of $174.9 million for the nine months ended September 30, 2015. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Liquidity and Capital Resources — Non-GAAP Financial Measures.” For more information regarding our financial results for 2016, see “— Results of Operations” below.
During the third quarter of 2016, we continued to operate three drilling rigs in the Delaware Basin, as we have throughout 2016. In the third quarter and at November 1, 2016, one of these rigs was drilling in the Wolf asset area in Loving County, Texas, one was drilling in the Rustler Breaks asset area in Eddy County, New Mexico and one was drilling in the western portion of our Ranger asset area in Lea County, New Mexico. We contracted a fourth drilling rig in late August 2016 to begin drilling our first salt water disposal well in the Rustler Breaks asset area. After this well is finished being drilled in early

21


November 2016, we intend to move this rig to our Wolf asset area to drill a third salt water disposal well there. Although we had made no commitment to do so at November 1, 2016, we are considering retaining the fourth drilling rig following the drilling of the Wolf salt water disposal well, and if so, we expect to move this rig to our Rustler Breaks asset area in early December 2016 and begin operating two drilling rigs there.
We began producing oil and natural gas from a total of 15 gross (8.4 net) wells in the Rustler Breaks and Wolf asset areas during the third quarter of 2016, including nine gross (7.9 net) operated and six gross (0.5 net) non-operated horizontal wells. Most of these wells were placed on production during August and September 2016 and, as a result, did not contribute fully to third quarter production volumes. In the Rustler Breaks asset area, we began producing oil and natural gas from a total of 11 gross (4.6 net) wells during the third quarter of 2016, including five gross (4.1 net) operated and six gross (0.5 net) non-operated horizontal wells. Of the five gross operated wells in the Rustler Breaks asset area, four were Wolfcamp A-XY completions and one was a lower Wolfcamp B (Blair Shale) completion. The six gross non-operated wells in the Rustler Breaks asset area included four Wolfcamp B (Blair Shale) completions and two Second Bone Spring completions. In addition, we began producing oil and natural gas from four gross (3.8 net) operated horizontal wells at Wolf during the third quarter of 2016, including one Wolfcamp A-Y completion and three Second Bone Spring completions.
As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production has continued to increase over the past twelve months. Our total Delaware Basin production for the third quarter of 2016 was 18,498 BOE per day, consisting of 11,751 Bbl of oil per day and 40.5 MMcf of natural gas per day, a 2.4-fold increase from production of 7,551 BOE per day, consisting of 5,489 Bbl of oil per day and 12.4 MMcf of natural gas per day, in the third quarter of 2015. The Delaware Basin contributed approximately 79% of our daily oil production and approximately 47% of our daily natural gas production in the third quarter of 2016, as compared to approximately 44% of our daily oil production and approximately 15% of our daily natural gas production in the third quarter of 2015.
In late August 2016, we successfully completed and began operating the Black River cryogenic natural gas processing plant built in our Rustler Breaks asset area in Eddy County, New Mexico. The Black River processing plant has an inlet capacity of approximately 60 MMcf of natural gas per day, which is almost twice the size of the previous cryogenic processing plant we built in our Wolf asset area in Loving County, Texas and subsequently sold to an affiliate of EnLink Midstream Partners, LP in October 2015. The Black River plant and associated gathering system was built to support our ongoing and future development efforts at Rustler Breaks and to provide us with priority one takeaway and processing services for our Rustler Breaks natural gas production. It should also provide additional income through the gathering and processing of third-party natural gas. The Black River plant was completed on time and on budget and, at November 1, 2016, had processed between 30 and 40 MMcf per day (on a gross basis) during its first two months in operation. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks.
On November 1, 2016, we adjusted our 2016 capital expenditure budget from $325.0 million to between $425.0 and $450.0 million, primarily to take advantage of a number of strategic lease and minerals acquisition opportunities as well as several new midstream initiatives in the Delaware Basin. More specifically, these changes in our capital budget should allow us (i) to take advantage of opportunities to make strategic additions to our Delaware Basin acreage and minerals position, particularly in the third and fourth quarters of 2016, as operational results have exceeded expectations and commodity prices have improved, (ii) to accelerate the timing of several important midstream projects originally planned for 2017, which add to our midstream asset base and (iii) to potentially add a fourth rig to our Delaware Basin drilling program in December 2016. Further, this estimated increase in our capital budget for 2016 does not include any additional funds allocated to drilling, completing and equipping wells in 2016. At September 30, 2016, we had incurred $333.5 million of our adjusted 2016 capital expenditure budget of between $425.0 and $450.0 million. For more information regarding our 2016 capital expenditure budget, see “— Liquidity and Capital Resources” below.
At December 31, 2015, we held approximately 157,100 gross (88,800 net) leased acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. Between January 1, 2016 and October 31, 2016, we added approximately 10,600 gross (7,300 net) leased acres in Southeast New Mexico and West Texas, bringing our total Permian Basin acreage position at October 31, 2016 to approximately 165,500 gross (94,700 net) leased acres, almost all of which was located in the Delaware Basin. At October 31, 2016, we had sold approximately 600 net acres and allowed to expire approximately 800 net acres in non-core areas of the Permian Basin in 2016. During the third quarter of 2016, we also acquired mineral ownership in approximately 600 net acres in our Rustler Breaks and Ranger/Arrowhead asset areas. This brings our total acquired mineral ownership in the Delaware Basin since January 1, 2016 to approximately 7,900 gross (2,300 net) mineral acres. We plan to continue our leasing and acquisition efforts in the Delaware Basin during the remainder of 2016 and may also consider acquiring acreage in the Eagle Ford and Haynesville shales as strategic opportunities are identified.


22


Estimated Proved Reserves
The following table sets forth our estimated total proved oil and natural gas reserves at September 30, 2016, December 31, 2015 and September 30, 2015. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that would be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total proved reserves are estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
 
September 30, 
 2016
 
December 31,
2015
 
September 30, 
 2015
Estimated Proved Reserves Data: (1) (2)
 
 
 
 
 
Estimated proved reserves:
 
 
 
 
 
Oil (MBbl)(3)
55,031

 
45,644

 
42,531

Natural Gas (Bcf)(4)
279.4

 
236.9

 
267.5

Total (MBOE)(5)
101,604

 
85,127

 
87,109

Estimated proved developed reserves:
 
 
 
 
 
Oil (MBbl)(3)
21,204

 
17,129

 
17,413

Natural Gas (Bcf)(4)
118.8

 
101.4

 
97.7

Total (MBOE)(5)
41,012

 
34,037

 
33,685

Percent developed
40.4
%
 
40.0
%
 
38.7
%
Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MBbl)(3)
33,827

 
28,515

 
25,118

Natural Gas (Bcf)(4)
160.6

 
135.5

 
169.8

Total (MBOE)(5)
60,592

 
51,090

 
53,424

Standardized Measure(6) (in millions)
$
516.8

 
$
529.2

 
$
673.8

PV-10(7) (in millions)
$
524.7

 
$
541.6

 
$
692.7

_______________
(1)
Numbers in table may not total due to rounding.
(2)
Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from October 2015 through September 2016 were $38.17 per Bbl for oil and $2.28 per MMBtu for natural gas, for the period from January 2015 through December 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas and for the period from October 2014 through September 2015 were $55.73 per Bbl for oil and $3.06 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
(3)
One thousand barrels of oil.
(4)
One billion cubic feet of natural gas.
(5)
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(6)
Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(7)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at September 30, 2016,

23


December 31, 2015 and September 30, 2015 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at September 30, 2016, December 31, 2015 and September 30, 2015 were, in millions, $7.9, $12.4 and $18.9, respectively.
At September 30, 2016, our estimated total proved oil and natural gas reserves were 101.6 million BOE, an all-time high, including 55.0 million Bbl of oil and 279.4 Bcf of natural gas, with a Standardized Measure of $516.8 million and a PV-10, a non-GAAP financial measure, of $524.7 million. At December 31, 2015, our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, and at September 30, 2015, our estimated total proved oil and natural gas reserves were 87.1 million BOE, including 42.5 million Bbl of oil and 267.5 Bcf of natural gas. Our proved oil reserves of 55.0 million Bbl at September 30, 2016, also an all-time high, increased 21%, as compared to 45.6 million Bbl at December 31, 2015, and increased 29%, as compared to 42.5 million Bbl at September 30, 2015. At September 30, 2016, approximately 40% of our total proved reserves were proved developed reserves, 54% of our total proved reserves were oil and 46% of our total proved reserves were natural gas.
As a result of our drilling, completion and delineation activities in West Texas and Southeast New Mexico since 2014, our Delaware Basin oil and natural gas reserves have become a more significant component of our total oil and natural gas reserves. Our estimated Delaware Basin proved oil and natural gas reserves have increased 87% from 39.6 million BOE at September 30, 2015, or 46% of our total proved oil and natural gas reserves, including 25.6 million Bbl of oil and 84.0 Bcf of natural gas, to 74.0 million BOE, or 73% of our total proved oil and natural gas reserves, including 44.1 million Bbl of oil and 179.3 Bcf of natural gas, at September 30, 2016.
There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in the Annual Report.
Critical Accounting Policies
There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.
Recent Accounting Pronouncements
See Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for the Company’s adoption of a new accounting pronouncement in the second quarter of 2016 and for a summary of recent accounting pronouncements that we believe may have an impact on our financial statements upon adoption.

24


Results of Operations
Revenues
The following table summarizes our unaudited revenues and production data for the periods indicated:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2016
 
2015
 
2016
 
2015
Operating Data:
 
 
 
 
 
 
 
Revenues (in thousands):(1)
 
 
 
 
 
 
 
Oil
$
58,589

 
$
50,173

 
$
141,437

 
$
162,424

Natural gas
24,490

 
21,642

 
54,904

 
59,704

Total oil and natural gas revenues
83,079

 
71,815

 
196,341

 
222,128

Third-party midstream services revenues
1,566

 
569

 
2,956

 
1,384

Realized gain on derivatives
885

 
19,862

 
10,413

 
52,146

Unrealized gain (loss) on derivatives
3,203

 
6,733

 
(30,261
)
 
(25,356
)
Total revenues
$
88,733

 
$
98,979

 
$
179,449

 
$
250,302

Net Production Volumes:(1)
 
 
 
 
 
 
 
Oil (MBbl)(2)
1,376

 
1,161

 
3,650

 
3,429

Natural gas (Bcf)(3)
8.0

 
7.5

 
22.6

 
21.1

Total oil equivalent (MBOE)(4)
2,703

 
2,405

 
7,423

 
6,941

Average daily production (BOE/d)(5)
29,381

 
26,137

 
27,091

 
25,427

Average Sales Prices:
 
 
 
 
 
 
 
Oil, without realized derivatives (per Bbl)
$
42.57

 
$
43.21

 
$
38.75

 
$
47.36

Oil, with realized derivatives (per Bbl)
$
43.18

 
$
57.90

 
$
40.63

 
$
59.61

Natural gas, without realized derivatives (per Mcf)
$
3.08

 
$
2.90

 
$
2.43

 
$
2.83

Natural gas, with realized derivatives (per Mcf)
$
3.08

 
$
3.28

 
$
2.58

 
$
3.31

_________________
(1)
We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with extracted natural gas liquids are included with our natural gas revenues.
(2)
One thousand barrels of oil.
(3)
One billion cubic feet of natural gas.
(4)
One thousand barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)
Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Three Months Ended September 30, 2016 as Compared to Three Months Ended September 30, 2015
Oil and natural gas revenues. Our oil and natural gas revenues increased $11.3 million to $83.1 million, or an increase of 16%, for the three months ended September 30, 2016, as compared to $71.8 million for the three months ended September 30, 2015. Our oil revenues increased $8.4 million, or 17%, to $58.6 million for the three months ended September 30, 2016, as compared to $50.2 million for the three months ended September 30, 2015. The increase in oil revenues was primarily from an increase in oil production of 19% to 1.38 million Bbl of oil for the three months ended September 30, 2016, or about 14,960 Bbl of oil per day, as compared to 1.16 million Bbl of oil, or about 12,617 Bbl of oil per day, for the three months ended September 30, 2015. The increase in oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not drilled any new operated wells since the second quarter of 2015. The increase in oil revenues was partially offset by a lower weighted average oil price realized for the three months ended September 30, 2016 of $42.57 per Bbl, as compared to $43.21 per Bbl realized for the three months ended September 30, 2015. Our natural gas revenues increased by $2.8 million, or 13%, to $24.5 million for the three months ended September 30, 2016, as compared to $21.6 million for the three months ended September 30, 2015. The increase in natural gas revenues resulted from a higher weighted average natural gas price realized for the three months ended September 30, 2016 of $3.08 per Mcf, as compared to $2.90 per Mcf realized for the three months ended September 30, 2015, and the 7% increase in our natural gas production to 8.0 Bcf for the three months ended September 30, 2016, as compared to 7.5 Bcf for the three months ended September 30, 2015. The increased natural gas production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin, which offset declining natural gas production in the Eagle Ford and Haynesville shales where we have significantly reduced our activity since late 2014 and early 2015.

25


Third-party midstream services revenues. During the third quarter of 2016, our midstream operations became a reportable business segment under U.S. GAAP. Thus, we reported third-party midstream services revenues separately for the first time in our unaudited condensed consolidated statements of operations. Third-party midstream services revenues are primarily those revenues from midstream operations related to third parties, including working interest owners in our operated wells; all midstream services revenues associated with Company-owned production are eliminated in consolidation. Our midstream services revenues from third-parties increased $1.0 million to $1.6 million, or an increase of 175%, for the three months ended September 30, 2016, as compared to $0.6 million for the three months ended September 30, 2015. This increase is primarily attributable to a significant increase in third-party salt water being disposed of at our commercial facilities in the Wolf asset area and to the Black River natural gas processing plant becoming operational in late August 2016. Prior to this time, we had no significant midstream services revenues attributable to natural gas processing plant operations.
Realized gain on derivatives. Our realized gain on derivatives was $0.9 million for the three months ended September 30, 2016, as compared to a realized gain of $19.9 million for the three months ended September 30, 2015. We realized net gains of $0.8 million and $48,500 from our oil and natural gas derivative contracts, respectively, for the three months ended September 30, 2016. For the three months ended September 30, 2015, we realized net gains of $17.1 million, $2.2 million and $0.6 million attributable to our oil, natural gas and natural gas liquids (“NGL”) derivative contracts, respectively. The realized gains on our oil and natural gas derivative contracts during the respective periods were attributable to commodity prices being below the floor prices of certain of our oil and natural gas costless collar contracts for the three months ended September 30, 2016 and 2015. The realized gain on our NGL derivative contracts during the three months ended September 30, 2015 resulted from NGL prices that were lower than the fixed prices of our NGL swap contracts; we had no open NGL derivative contracts in 2016. The average floor prices of our oil costless collar contracts were $42.48 per Bbl and $67.11 per Bbl for the three months ended September 30, 2016 and 2015, respectively. The average ceiling prices of our oil costless collar contracts were $61.16 per Bbl and $84.60 per Bbl for the three months ended September 30, 2016 and 2015, respectively. The average floor prices of our natural gas costless collar contracts were $2.60 per MMBtu and $3.26 per MMBtu for the three months ended September 30, 2016 and 2015, respectively. The average ceiling prices of our natural gas costless collar contracts were $3.53 per MMBtu and $3.94 per MMBtu for the three months ended September 30, 2016 and 2015, respectively. Our total oil and natural gas volumes hedged for the three months ended September 30, 2016 were 15% lower and 31% lower, respectively, than the total oil and natural gas volumes hedged for the same period in 2015.
Unrealized gain on derivatives. Our unrealized gain on derivatives was $3.2 million for the three months ended September 30, 2016, as compared to an unrealized gain of $6.7 million for the three months ended September 30, 2015. During the three months ended September 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts increased to a liability of $14.0 million from a liability of $17.2 million at June 30, 2016, resulting in an unrealized gain on derivatives of $3.2 million for the three months ended September 30, 2016. During the three months ended September 30, 2016, the net fair value of our open oil derivative contracts increased by $2.0 million, and the net fair value of our open natural gas derivative contracts increased by $1.2 million. During the three months ended September 30, 2015, the aggregate net fair value of our open oil, natural gas and NGL derivative contracts increased to an asset of $30.2 million from $23.5 million at June 30, 2015, resulting in an unrealized gain on derivatives of $6.7 million for the three months ended September 30, 2015.
Nine Months Ended September 30, 2016 as Compared to Nine Months Ended September 30, 2015
Oil and natural gas revenues. Our oil and natural gas revenues decreased by approximately $25.8 million, or 12%, to $196.3 million for the nine months ended September 30, 2016, as compared to $222.1 million for the nine months ended September 30, 2015. Our oil revenues decreased by 13% to $141.4 million for the nine months ended September 30, 2016, as compared to $162.4 million for the nine months ended September 30, 2015. The decrease in oil revenues resulted primarily from a lower weighted average oil price realized for the nine months ended September 30, 2016 of $38.75 per Bbl, as compared to $47.36 per Bbl realized for the nine months ended September 30, 2015. Our oil production increased by 6% to 3.65 million Bbl for the nine months ended September 30, 2016, or about 13,322 Bbl of oil per day, as compared to 3.43 million Bbl of oil, or about 12,562 Bbl of oil per day, for the nine months ended September 30, 2015. The increase in oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not drilled any new operated wells since the second quarter of 2015. Our natural gas revenues decreased by $4.8 million, or 8%, to $54.9 million for the nine months ended September 30, 2016, as compared to $59.7 million for the nine months ended September 30, 2015. Our natural gas production increased by 7% to 22.6 Bcf for the nine months ended September 30, 2016, as compared to 21.1 Bcf for the nine months ended September 30, 2015. The increase in natural gas production was primarily attributable to increased natural gas production associated with our operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2015 and into 2016. This production increase was more than offset by a lower weighted average natural gas price of $2.43 per Mcf realized during the nine months ended September 30, 2016, as compared to a weighted average natural gas price of $2.83 per Mcf realized during the nine months ended September 30, 2015.

26


Third-party midstream services revenues. Our midstream services revenues from third parties increased $1.6 million to $3.0 million, or an increase of 114% for the nine months ended September 30, 2016, as compared to $1.4 million for the nine months ended September 30, 2015. This is primarily attributable to a significant increase in third-party salt water being disposed of at our commercial facilities in the Wolf asset area and to the Black River natural gas processing plant becoming operational in late August 2016. Prior to this time, we had no significant midstream services revenues attributable to natural gas processing plant operations.
Realized gain on derivatives. We realized a gain on derivatives of approximately $10.4 million for the nine months ended September 30, 2016, as compared to a gain of approximately $52.1 million for the nine months ended September 30, 2015. For the nine months ended September 30, 2016, we realized net gains of approximately $6.9 million and $3.6 million attributable to our oil and natural gas derivative contracts, respectively. For the nine months ended September 30, 2015, we realized net gains of approximately $42.0 million, $8.5 million and $1.6 million attributable to our oil, natural gas and NGL derivative contracts, respectively. The net gain realized from our derivative contracts for the nine months ended September 30, 2016 resulted from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas derivative contracts. The average floor prices of our oil costless collar contracts were $43.17 per Bbl and $71.77 per Bbl for the nine months ended September 30, 2016 and 2015, respectively. The average ceiling prices of our oil costless collar contracts were $63.04 per Bbl and $89.04 per Bbl for the nine months ended September 30, 2016 and 2015, respectively. The average floor prices of our natural gas costless collar contracts were $2.61 per MMBtu and $3.42 per MMBtu for the nine months ended September 30, 2016 and 2015, respectively. The average ceiling prices of our natural gas costless collar contracts were $3.55 per MMBtu and $4.19 per MMBtu for the nine months ended September 30, 2016 and 2015, respectively. Our total oil and natural gas volumes hedged for the nine months ended September 30, 2016 were 2% lower and 35% lower, respectively, than the total oil and natural gas volumes hedged for the same period in 2015.
Unrealized loss on derivatives. Our unrealized loss on derivatives was approximately $30.3 million for the nine months ended September 30, 2016, as compared to an unrealized loss of approximately $25.4 million for the nine months ended September 30, 2015. During the period from December 31, 2015 through September 30, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased from an asset of approximately $16.3 million to a liability of approximately $14.0 million, resulting in an unrealized loss on derivatives of approximately $30.3 million for the nine months ended September 30, 2016. During the period from December 31, 2014 through September 30, 2015, the aggregate net fair value of our open oil, natural gas and NGL derivative contracts decreased from $55.5 million to $30.2 million, resulting in an unrealized loss on derivatives of $25.4 million for the nine months ended September 30, 2015.

27


Expenses
The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
(In thousands, except expenses per BOE)
2016
 
2015
 
2016
 
2015
 
Expenses:
 
 
 
 
 
 
 
 
Production taxes, transportation and processing
$
12,388

 
$
9,426

 
$
30,846

 
$
26,734

 
Lease operating
14,605

 
13,466

 
41,300

 
40,140

 
Plant and other midstream services operating
1,449

 
1,450

 
3,537

 
2,772

 
Depletion, depreciation and amortization
30,015

 
45,237

 
90,185

 
143,477

 
Accretion of asset retirement obligations
276

 
182

 
828

 
427

 
Full-cost ceiling impairment

 
285,721

 
158,633

 
581,874

 
General and administrative
13,146

 
12,151

 
39,506

 
38,523

 
Total expenses
$
71,879

 
$
367,633

 
$
364,835

 
$
833,947

 
Operating income (loss)
$
16,854

 
$
(268,654
)
 
$
(185,386
)
 
$
(583,645
)
 
Other income (expense):
 
 
 
 
 
 
 
 
Net gain (loss) on asset sales and inventory impairment
$
1,073

 
$

 
$
3,140

 
$
(97
)
 
Interest expense
(6,880
)
 
(7,229
)
 
(20,244
)
 
(15,168
)
 
Other (expense) income
(141
)
 
564

 
(17
)
 
637

 
Total other expense
$
(5,948
)
 
$
(6,665
)
 
$
(17,121
)
 
$
(14,628
)
 
Income (loss) before income taxes
$
10,906

 
$
(275,319
)
 
$
(202,507
)
 
$
(598,273
)
 
Total income tax benefit
(1,141
)
 
(33,305
)
 
(1,141
)
 
(149,045
)
 
Net income attributable to non-controlling interest in subsidiaries
(116
)
 
(45
)
 
(209
)
 
(156
)
 
Net income (loss) attributable to Matador Resources Company shareholders
$
11,931

 
$
(242,059
)
 
$
(201,575
)
 
$
(449,384
)
 
Expenses per BOE:
 
 
 
 
 
 
 
 
Production taxes, transportation and processing
$
4.58

 
$
3.92

(1) 
$
4.16

 
$
3.85

(2) 
Lease operating
$
5.40

 
$
5.60

(3) 
$
5.56

 
$
5.78

(4) 
Plant and other midstream services operating
$
0.54

 
$
0.60

 
$
0.48

 
$
0.40

 
Depletion, depreciation and amortization
$
11.10

 
$
18.81

 
$
12.15

 
$
20.67

 
General and administrative