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EX-32 - CONCHO RESOURCES INCcxo_2Q15_exhibit_32_1.htm

 

                                                                         

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

 

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2015

or

 

 

 

o

 

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: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

 

76-0818600

 

 

 

(State or other jurisdiction

 

(I.R.S. Employer

of incorporation or organization)

 

Identification No.)

 

 

 

 One Concho Center

 

 

600 West Illinois Avenue

 

 

Midland, Texas  

 

79701

 

 

 

(Address of principal executive offices)

 

(Zip code)

 

 

 

 

 

        (432) 683-7443

 

 

 

 

(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. Yes No o  

 

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). Yes No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ☑ 

Accelerated filer

 

 

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 o No ☑  

 

Number of shares of the registrant’s common stock outstanding at July 27, 2015: 120,302,606 shares

 

 

                                                                         

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

 

PART I – FINANCIAL INFORMATION:

iii

 

 

 

 

Item 1. Consolidated Financial Statements (Unaudited)

iii

 

 

 

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

28

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

50

 

 

 

 

Item 4. Controls and Procedures

52

 

 

 

PART II – OTHER INFORMATION:

53

 

 

 

 

Item 1. Legal Proceedings

53

 

 

 

 

Item 1A. Risk Factors

53

 

 

 

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

53

 

 

 

 

Item 6. Exhibits  

54

i 


 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this “Quarterly Report”) that express a belief, expectation, or intention, or that are not statements of historical fact, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, as well as those factors summarized below:

·         declines in the prices we receive for our oil and natural gas;

·         uncertainties about the estimated quantities of oil and natural gas reserves;

·         drilling and operating risks, including risks related to properties where we do not serve as the operator;

·         the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our credit facility;

·         the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas;

·         environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

·         difficult and adverse conditions in the domestic and global capital and credit markets;

·         risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas;

·         disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver oil, natural gas liquids and natural gas and other processing and transportation considerations;

·         the costs and availability of equipment, resources, services and personnel required to perform our drilling and operating activities;

·         potential financial losses or earnings reductions from our commodity price management program;

·         risks and liabilities associated with acquired properties or businesses;

·         uncertainties about our ability to successfully execute our business and financial plans and strategies;

·         uncertainties about our ability to replace reserves and economically develop our current reserves;

·         general economic and business conditions, either internationally or domestically;

·         competition in the oil and natural gas industry; and

·         uncertainty concerning our assumed or possible future results of operations.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

  

ii  


 

PART I – FINANCIAL INFORMATION

 

Item 1.  Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at June 30, 2015 and December 31, 2014

1

 

 

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014

2

 

 

Consolidated Statement of Stockholders’  Equity for the Six Months Ended June 30, 2015

3

 

 

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014

4

 

 

Condensed Notes to Consolidated Financial Statements

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

iii  


 

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

 

 

 

 

 

 

 

June 30,

 

 

December 31,

(in thousands, except share and per share amounts)

 

 

2015

 

 

2014

Assets

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

280

 

$

21

 

Accounts receivable, net of allowance for doubtful accounts:

 

 

 

 

 

 

 

 

Oil and natural gas

 

 

251,497

 

 

250,600

 

 

Joint operations and other

 

 

257,956

 

 

409,665

 

Derivative instruments

 

 

351,360

 

 

490,351

 

Prepaid costs and other

 

 

40,599

 

 

37,759

 

 

  

Total current assets

 

 

901,692

 

 

1,188,396

Property and equipment:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

 

15,183,313

 

 

13,867,831

 

Accumulated depletion and depreciation

 

 

(4,353,015)

 

 

(3,790,953)

 

 

Total oil and natural gas properties, net

 

 

10,830,298

 

 

10,076,878

 

Other property and equipment, net

 

 

146,138

 

 

129,136

 

 

Total property and equipment, net

 

 

10,976,436

 

 

10,206,014

Deferred loan costs, net

 

 

63,497

 

 

68,443

Intangible asset - operating rights, net

 

 

26,424

 

 

27,154

Inventory

 

 

16,365

 

 

14,435

Noncurrent derivative instruments

 

 

93,843

 

 

262,349

Other assets

 

 

75,719

 

 

33,172

 

Total assets

 

$

12,153,976

 

$

11,799,963

Liabilities and Stockholders’ Equity

Current liabilities:

 

 

 

 

 

 

 

Accounts payable - trade

 

$

44,895

 

$

20,380

 

Bank overdrafts

 

 

82,170

 

 

92,541

 

Revenue payable

 

 

202,542

 

 

238,098

 

Accrued and prepaid drilling costs

 

 

472,424

 

 

718,300

 

Deferred income taxes

 

 

115,781

 

 

162,566

 

Other current liabilities

 

 

181,317

 

 

195,308

 

 

  

Total current liabilities

 

 

1,099,129

 

 

1,427,193

Long-term debt

 

 

3,582,465

 

 

3,517,320

Deferred income taxes

 

 

1,389,702

 

 

1,438,185

Noncurrent derivative instruments

 

 

3,970

 

 

-

Asset retirement obligations and other long-term liabilities

 

 

140,563

 

 

136,477

Commitments and contingencies (Note 9)

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

Common stock, $0.001 par value; 300,000,000 authorized; 120,600,497 and

 

 

 

 

 

 

 

 

113,264,918 shares issued at June 30, 2015 and December 31, 2014, respectively

 

 

121

 

 

113

 

Additional paid-in capital

 

 

3,802,137

 

 

3,027,412

 

Retained earnings

 

 

2,166,770

 

 

2,279,741

 

Treasury stock, at cost; 299,249 and 260,124 shares at June 30, 2015 and

 

 

 

 

 

 

 

 

December 31, 2014, respectively

 

 

(30,881)

 

 

(26,478)

 

 

  

Total stockholders’ equity

 

 

5,938,147

 

 

5,280,788

 

Total liabilities and stockholders’ equity

 

$

12,153,976

 

$

11,799,963

 

 

 

 

 

 

 

 

 

 

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

 

 

1 


 

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

June 30,

 

June 30,

(in thousands, except per share amounts)

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

470,890

 

$

580,772

 

$

820,474

 

$

1,120,629

 

Natural gas sales

 

 

66,535

 

 

123,930

 

 

130,473

 

 

245,032

 

 

Total operating revenues

 

 

537,425

 

 

704,702

 

 

950,947

 

 

1,365,661

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas production

 

 

142,265

 

 

134,944

 

 

267,800

 

 

261,868

 

Exploration and abandonments

 

 

12,020

 

 

28,288

 

 

17,775

 

 

53,663

 

Depreciation, depletion and amortization

 

 

304,802

 

 

237,445

 

 

572,007

 

 

458,837

 

Accretion of discount on asset retirement obligations

 

 

2,047

 

 

1,722

 

 

4,041

 

 

3,393

 

General and administrative (including non-cash stock-based compensation of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$15,450 and $9,775 for the three months ended June 30, 2015 and 2014,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

respectively, and $30,945 and $21,207 for the six months ended

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015 and 2014, respectively)

 

 

60,923

 

 

49,535

 

 

119,724

 

 

97,285

 

Loss on derivatives not designated as hedges

 

 

147,399

 

 

164,707

 

 

32,059

 

 

200,322

 

 

Total operating costs and expenses

 

 

669,456

 

 

616,641

 

 

1,013,406

 

 

1,075,368

Income (loss) from operations

 

 

(132,031)

 

 

88,061

 

 

(62,459)

 

 

290,293

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(53,482)

 

 

(55,388)

 

 

(107,051)

 

 

(111,523)

 

Loss on extinguishment of debt

 

 

-

 

 

(4,316)

 

 

-

 

 

(4,316)

 

Other, net

 

 

(5,678)

 

 

(9,529)

 

 

(10,019)

 

 

(8,988)

 

 

Total other expense

 

 

(59,160)

 

 

(69,233)

 

 

(117,070)

 

 

(124,827)

Income (loss) before income taxes

 

 

(191,191)

 

 

18,828

 

 

(179,529)

 

 

165,466

 

Income tax (expense) benefit

 

 

70,708

 

 

(7,059)

 

 

66,558

 

 

(62,390)

Net income (loss)

 

$

(120,483)

 

$

11,769

 

$

(112,971)

 

$

103,076

Earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income (loss)

 

$

(1.02)

 

$

0.11

 

$

(0.97)

 

$

0.96

 

Diluted net income (loss)

 

$

(1.02)

 

$

0.11

 

$

(0.97)

 

$

0.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

2 


 

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Additional

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

Common Stock Issued

 

 

Paid-in

 

 

Retained

 

Treasury Stock

 

Stockholders’

(in thousands)

 

Shares

 

 

Amount

 

 

Capital

 

 

Earnings

 

Shares

 

 

Amount

 

 

Equity

BALANCE AT DECEMBER 31, 2014

 

113,265

 

$

113

 

$

3,027,412

 

$

2,279,741

 

260

 

$

(26,478)

 

$

5,280,788

 

Net loss

 

-

 

 

-

 

 

-

 

 

(112,971)

 

-

 

 

-

 

 

(112,971)

 

Issuance of common stock

 

6,900

 

 

7

 

 

741,502

 

 

-

 

-

 

 

-

 

 

741,509

 

Stock options exercised

 

4

 

 

1

 

 

57

 

 

-

 

-

 

 

-

 

 

58

 

Grants of restricted stock

 

447

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Cancellation of restricted stock

 

(16)

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Stock-based compensation

 

-

 

 

-

 

 

30,945

 

 

-

 

-

 

 

-

 

 

30,945

 

Excess tax benefits related to stock-based

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

compensation

 

-

 

 

-

 

 

2,221

 

 

-

 

-

 

 

-

 

 

2,221

 

Purchase of treasury stock

 

-

 

 

-

 

 

-

 

 

-

 

39

 

 

(4,403)

 

 

(4,403)

BALANCE AT JUNE 30, 2015

 

120,600

 

$

121

 

$

3,802,137

 

$

2,166,770

 

299

 

$

(30,881)

 

$

5,938,147

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

3 


 

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

  

 

 

 

 

 

June 30,

(in thousands)

 

2015

 

2014

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income (loss)

 

$

(112,971)

 

$

103,076

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

572,007

 

 

458,837

 

 

Accretion of discount on asset retirement obligations

 

 

4,041

 

 

3,393

 

 

Exploration and abandonments, including dry holes

 

 

12,352

 

 

41,762

 

 

Non-cash stock-based compensation expense

 

 

30,945

 

 

21,207

 

 

Deferred income taxes

 

 

(95,268)

 

 

34,951

 

 

(Gain) loss on disposition of assets and other

 

 

1,620

 

 

9,457

 

 

Loss on derivatives not designated as hedges

 

 

32,059

 

 

200,322

 

 

Other non-cash items

 

 

5,298

 

 

9,418

 

Changes in operating assets and liabilities, net of acquisitions and dispositions:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

55,870

 

 

(83,061)

 

 

 

Prepaid costs and other

 

 

(2,098)

 

 

(6,154)

 

 

 

Inventory

 

 

(1,935)

 

 

4,782

 

 

 

Accounts payable

 

 

23,339

 

 

36,626

 

 

 

Revenue payable

 

 

(35,556)

 

 

17,671

 

 

 

Other current liabilities

 

 

(769)

 

 

2,441

 

 

 

 

Net cash provided by operating activities

 

 

488,934

 

 

854,728

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Capital expenditures on oil and natural gas properties

 

 

(1,492,547)

 

 

(1,054,000)

 

Additions to property, equipment and other assets

 

 

(26,146)

 

 

(20,456)

 

Proceeds from the disposition of assets

 

 

96

 

 

394

 

Contribution to equity method investment

 

 

(45,000)

 

 

(10,050)

 

Settlements received from (paid on) derivatives not designated as hedges

 

 

279,408

 

 

(40,891)

 

  

 

 

Net cash used in investing activities

 

 

(1,284,189)

 

 

(1,125,003)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Proceeds from issuance of debt

 

 

1,097,400

 

 

1,578,000

 

Payments of debt

 

 

(1,030,900)

 

 

(1,828,000)

 

Exercise of stock options

 

 

58

 

 

1,289

 

Excess tax benefit from stock-based compensation

 

 

2,221

 

 

4,000

 

Net proceeds from issuance of common stock

 

 

741,509

 

 

932,455

 

Payments for loan costs

 

 

-

 

 

(10,642)

 

Purchase of treasury stock

 

 

(4,403)

 

 

(4,642)

 

Decrease in bank overdrafts

 

 

(10,371)

 

 

(36,718)

 

  

 

 

Net cash provided by financing activities

 

 

795,514

 

 

635,742

 

  

 

 

Net increase in cash and cash equivalents

 

 

259

 

 

365,467

Cash and cash equivalents at beginning of period

 

 

21

 

 

21

Cash and cash equivalents at end of period

 

$

280

 

$

365,488

 

 

 

 

 

 

 

 

 

 

 

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

 

 

4 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 1. Organization and nature of operations

 

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development and exploration of oil and natural gas properties primarily located in the Permian Basin region of Southeast New Mexico and West Texas.  

 

Note 2. Summary of significant accounting policies

 

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

 

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value of business combinations, fair value of stock-based compensation and income taxes.

 

Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2014 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

 

Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

 

Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods. The Company had deferred loan costs of $63.5 million and $68.4 million, net of accumulated amortization of $64.6 million and $59.7 million, at June 30, 2015 and December 31, 2014, respectively.

 

Equity method investment. The Company owns a 50 percent member interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the member interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months. The Company accounts for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC is $74.3 million at June 30, 2015 and is included in other assets in the Company’s consolidated balance sheet. The equity loss for the six months ended June 30, 2015 is approximately $1.7 million and is included in other expense in the Company’s consolidated statement of operations. During the six months ended June 30, 2015, the Company recorded $1.5 million of capitalized interest on its investment in ACC.

5 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

 

Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.  

 

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $6.4 million and $5.9 million for the three months ended June 30, 2015 and 2014, respectively, and $12.7 million and $11.0 million for the six months ended June 30, 2015 and 2014, respectively.

 

Recent accounting pronouncements. In April 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest–Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented as a direct deduction from the carrying amount of that debt liability. The Company currently presents debt issuance costs on the balance sheet as an asset.

 

An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. The Company plans to early adopt this ASU on December 31, 2015. As of June 30, 2015, the Company had $45.6 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability.

 

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

 

The original effective date to apply ASU 2014-09 was for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. However, on July 9, 2015, the FASB voted to approve a one-year deferral of the effective date of this standard, which when formalized in an ASU, will move the effective date to annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

 

Note 3. Exploratory well costs

 

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 16 for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.

  

6 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

The following table reflects the Company’s net capitalized exploratory well activity during the six months ended June 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

Six Months Ended

(in thousands)

 

  

June 30, 2015

 

 

 

 

 

 

 

 

Beginning capitalized exploratory well costs

 

 

 

 

$

241,657

 

Additions to exploratory well costs pending the determination of proved reserves

 

 

 

 

 

109,894

 

Reclassifications due to determination of proved reserves

 

 

 

 

 

(214,981)

 

Exploratory well costs charged to expense

 

 

 

 

 

(532)

Ending capitalized exploratory well costs

 

 

 

 

$

136,038

 

 

 

 

 

 

 

 

 

The following table provides an aging at June 30, 2015 and December 31, 2014 of capitalized exploratory well costs based on the date drilling was completed:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

 

December 31,

(dollars in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  

$

127,694

 

$

232,346

Capitalized exploratory well costs that have been capitalized for a period greater than one year

  

 

8,344

 

  

9,311

 

Total capitalized exploratory well costs

  

$

136,038

 

$

241,657

Number of projects with exploratory well costs that have been capitalized for a period greater

 

 

 

 

 

 

 

than one year

 

 

3

 

 

7

 

 

  

 

 

 

 

 

 

Delaware Basin project. At June 30, 2015, the Company had approximately $5.3 million of suspended well costs greater than one year recorded for a well that was initially drilled to monitor nearby wells but is now undergoing tests to determine commercial production capability.

 

Projects operated by others. At June 30, 2015, the Company had approximately $3.0 million of suspended well costs greater than one year recorded for two wells that are operated by others and waiting on completion.

7 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 4. Asset retirement obligations

 

The Companys asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Companys asset retirement obligation activity during the six months ended June 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

(in thousands)

 

 

June 30, 2015

 

 

 

 

 

 

 

 

Asset retirement obligations, beginning of period

 

 

 

 

$

119,881

 

Liabilities incurred from new wells

  

 

 

 

  

2,905

 

Accretion expense

  

 

 

 

  

4,041

 

Liabilities settled upon plugging and abandoning wells

  

 

 

 

  

(3,031)

 

Revision of estimates

  

 

 

 

  

(12)

Asset retirement obligations, end of period

 

 

 

 

$

123,784

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Note 5.  Stock incentive plan

 

The Company’s 2015 Stock Incentive Plan provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company.

 

A summary of the Company’s activity for the six months ended June 30, 2015 is presented below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted

 

Stock

 

Performance

 

 

 

 

Stock

 

Options

 

Units

 

Outstanding at December 31, 2014

 

  

1,091,309

 

 

47,713

 

 

250,314

 

 

Awards granted (a)

 

  

447,208

 

 

-

 

 

176,330

 

 

Options exercised

 

  

-

 

 

(4,812)

 

 

-

 

 

Awards cancelled / forfeited

 

  

(16,441)

 

 

-

 

 

-

 

 

Lapse of restrictions

 

 

(259,699)

 

 

-

 

 

-

 

Outstanding at June 30, 2015

 

1,262,377

 

42,901

 

426,644

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Weighted average grant date fair value per share

 

$

109.79

 

$

-

 

$

156.86

 

 

 

 

  

 

 

 

 

 

 

 

8 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at June 30, 2015:

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2015

 

$

32,253

2016

 

  

47,633

2017

 

  

27,324

2018

 

  

6,393

2019

 

  

246

Thereafter

 

 

4

 

Total

  

$

113,853

 

 

 

 

 

 

Note 6. Disclosures about fair value measurements

 

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

 

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

 

Level 2:     Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

 

Level 3:     Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

9 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Financial Assets and Liabilities Measured at Fair Value

 

The following table presents the carrying amounts and fair values of the Company’s financial instruments at June 30, 2015 and December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

December 31, 2014

 

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

(in thousands)

 

Value

 

Value

 

Value

 

Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

445,203

 

$

445,203

 

$

752,700

 

$

752,700

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

3,970

 

$

3,970

 

$

-

 

$

-

 

 

Credit facility

 

$

206,000

 

$

195,793

 

$

139,500

 

$

131,068

 

 

7.0% senior notes due 2021

 

$

600,000

 

$

628,500

 

$

600,000

 

$

625,500

 

 

6.5% senior notes due 2022

 

$

600,000

 

$

624,000

 

$

600,000

 

$

628,500

 

 

5.5% senior notes due 2022

 

$

600,000

 

$

597,360

 

$

600,000

 

$

598,500

 

 

5.5% senior notes due 2023

 

$

1,576,465

 

$

1,580,406

 

$

1,577,820

 

$

1,573,875

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, interest payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

 

Credit facility. The fair value of the Company’s credit facility is estimated by discounting the principal and interest payments at the Company’s credit-adjusted discount rate at the reporting date, which utilizes inputs that are Level 2 measurements in the fair value hierarchy.

 

Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.

  

10 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and 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 (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at June 30, 2015 and December 31, 2014. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

 

 

 

 

Fair Value Measurements Using

 

 

 

Net

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

Gross

 

 

Fair Value

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

Amounts

 

 

Presented

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

Offset in the

 

 

in the

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

 

 

 

Consolidated

 

 

Consolidated

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

Total

 

 

Balance

 

 

Balance

(in thousands)

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

Sheet

 

 

Sheet

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

-

 

$

392,672

 

$

-

 

$

392,672

 

$

(41,312)

 

$

351,360

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

100,436

 

  

-

 

  

100,436

 

  

(6,593)

 

  

93,843

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

 

(41,312)

 

 

-

 

 

(41,312)

 

 

41,312

 

 

-

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(10,563)

 

  

-

 

  

(10,563)

 

  

6,593

 

  

(3,970)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

441,233

 

$

-

 

$

441,233

 

$

-

 

$

441,233

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

 

 

 

Fair Value Measurements Using

 

 

 

Net

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

Gross

 

 

Fair Value

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

Amounts

 

 

Presented

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

Offset in the

 

 

in the

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

 

 

 

Consolidated

 

 

Consolidated

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

Total

 

 

Balance

 

 

Balance

(in thousands)

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

Sheet

 

 

Sheet

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

-

 

$

501,717

 

$

-

 

$

501,717

 

$

(11,366)

 

$

490,351

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

262,349

 

  

-

 

  

262,349

 

  

-

 

  

262,349

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(11,366)

 

  

-

 

  

(11,366)

 

  

11,366

 

  

-

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

-

 

  

-

 

  

-

 

  

-

 

  

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

752,700

 

$

-

 

$

752,700

 

$

-

 

$

752,700

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Concentrations of credit risk. At June 30, 2015, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 7 for additional information regarding the Company’s derivative activities.

12 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

 

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: 

 

Impairments of long-lived assets. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value of the properties would be recognized at that time.

 

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves and (iv) results of future drilling activities.

 

Based on the factors above as of June 30, 2015, the Company determined that undiscounted future cash flows attributable to certain depletion groups indicated that their carrying amounts were expected to be recovered; however, they may be at risk for impairment if management’s estimates of future cash flows further decline.

13 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 7. Derivative financial instruments

 

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical delivery contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

 

The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its statements of operations as they occur.

 

The following table summarizes the gains (losses) reported in earnings related to the commodity derivative instruments for the three and six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

 

June 30,

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

(146,549)

 

$

(163,655)

 

$

(36,269)

 

$

(187,875)

 

 

Natural gas derivatives

 

 

(850)

 

 

(1,052)

 

 

4,210

 

 

(12,447)

 

 

 

Total

 

$

(147,399)

 

$

(164,707)

 

$

(32,059)

 

$

(200,322)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents the Company’s cash receipts from (payments on) derivatives for the three and six months ended June 30, 2015 and 2014:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

 

June 30,

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash receipts from (payments on) derivatives not designated as hedges:

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

103,129

 

$

(24,569)

 

$

263,315

 

$

(34,338)

 

 

Natural gas derivatives

 

  

9,123

 

  

(1,485)

 

  

16,093

 

  

(6,553)

 

 

 

Total

 

$

112,252

 

$

(26,054)

 

$

279,408

 

$

(40,891)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

14 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Commodity derivative contracts at June 30, 2015. The following table sets forth the Company’s outstanding derivative contracts at June 30, 2015. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at June 30, 2015 are expected to settle by June 30, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

Oil Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2015:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

5,719,000

 

4,904,000

 

10,623,000

 

 

Price per Bbl

 

 

 

 

$

77.19

$

78.84

$

77.95

 

2016:

  

 

  

 

  

 

  

 

  

 

 

 

Volume (Bbl)

 

4,188,000

 

3,858,000

 

3,618,000

 

3,195,000

 

14,859,000

 

 

Price per Bbl

$

84.33

$

85.38

$

85.60

$

63.69

$

80.48

 

2017:

  

 

  

 

  

 

  

 

  

 

 

 

Volume (Bbl)

  

2,784,000

  

2,784,000

  

-

  

-

  

5,568,000

 

 

Price per Bbl

$

65.60

$

65.60

$

-

$

-

$

65.60

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2015:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

5,506,000

 

4,876,000

 

10,382,000

 

 

Price per Bbl

 

 

 

 

$

(2.65)

$

(2.72)

$

(2.68)

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

4,124,000

 

3,821,000

 

3,404,000

 

3,128,000

 

14,477,000

 

 

Price per Bbl

$

(2.05)

$

(2.11)

$

(2.17)

$

(2.22)

$

(2.13)

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

2,430,000

 

2,457,000

 

-

 

-

 

4,887,000

 

 

Price per Bbl

$

(1.67)

$

(1.67)

$

-

$

-

$

(1.67)

Natural Gas Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

5,980,000

 

5,980,000

 

11,960,000

 

 

Price per MMBtu

 

 

 

 

$

4.16

$

4.16

$

4.16

Natural Gas Basis Swaps: (d)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

1,380,000

 

1,380,000

 

2,760,000

 

 

Price per MMBtu

 

 

 

 

$

(0.13)

$

(0.13)

$

(0.13)

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate

 

(“WTI”) monthly average futures price.

(b) The basis differential price is between Midland – WTI and Cushing – WTI.

(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

(d) The basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative counterparties.  The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. Other than provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company.

15 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

At June 30, 2015, the Company had a net asset position of $441.2 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $64.9 million, $57.8 million, $54.2 million and $47.4 million with  J.P. Morgan Chase Bank, Wells Fargo Bank, N.A., Barclays Bank PLC and KeyBank National Association, respectively.  

 

Note 8. Debt 

 

The Company’s debt consisted of the following at June 30, 2015 and December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

 

December 31,

(in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

Credit facility

 

$

206,000

 

$

139,500

7.0% unsecured senior notes due 2021

 

  

600,000

 

  

600,000

6.5% unsecured senior notes due 2022

 

  

600,000

 

  

600,000

5.5% unsecured senior notes due 2022

 

  

600,000

 

  

600,000

5.5% unsecured senior notes due 2023

 

  

1,550,000

 

  

1,550,000

Unamortized original issue premium, net

 

  

26,465

 

  

27,820

 

Less: current portion

 

  

-

 

  

-

 

 

Total long-term debt

 

$

3,582,465

 

$

3,517,320

 

 

 

 

 

 

 

 

 

 

Credit facility. The Company’s credit facility, as amended and restated, has a maturity date of May 9, 2019. In April 2015, the Company amended its credit agreement to remove the current ratio financial covenant. The Company’s borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2016. At June 30, 2015, commitments from the Company’s bank group totaled $2.5 billion.

 

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by all subsidiaries of the Company, subject to customary release provisions as described in Note 14.

 

At June 30, 2015, the Company was in compliance with the covenants under all of its debt instruments.

 

Principal maturities of long-term debt.  Principal maturities of long-term debt outstanding at June 30, 2015 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Remaining 2015

 

$

 

-

2016

 

 

 

-

2017

 

 

 

-

2018

 

 

 

-

2019

 

 

 

206,000

2020

 

 

 

-

Thereafter

 

 

 

3,350,000

 

Total

$

 

3,556,000

 

 

 

 

 

 

16 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Interest expense.  The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

 

 

June 30,

 

June 30,

(in thousands)

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash payments for interest

  

$

59,225

 

$

65,480

  

$

105,232

 

$

109,800

Amortization of original issue discount (premium)

 

 

(681)

 

 

(645)

  

 

(1,355)

 

 

(1,282)

Amortization of deferred loan origination costs

 

 

2,482

 

 

2,725

  

 

4,945

 

 

6,072

Net changes in accruals

 

 

(6,365)

 

 

(12,172)

  

 

618

 

 

(3,067)

 

Interest costs incurred

 

 

54,661

 

 

55,388

  

 

109,440

 

 

111,523

Less: capitalized interest

 

 

(1,179)

 

 

-

 

 

(2,389)

 

 

-

 

Total interest expense

 

$

53,482

 

$

55,388

 

$

107,051

 

$

111,523

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Note 9. Commitments and contingencies

 

Severance agreements.   The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $7.9 million.

 

IndemnificationsThe Company has agreed to indemnify its directors and officers with respect to claims and damages arising from certain acts or omissions taken in such capacity.

 

Legal actionsThe Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

 

Severance tax, royalty and joint interest audits.  The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At June 30, 2015 and December 31, 2014, the Company had $12.1 million and $12.3 million accrued for estimated exposure, respectively. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. 

17 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments and power commitments. The following table summarizes the Company’s commitments at June 30, 2015:

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2015

 

$

27,341

2016

 

 

38,233

2017

 

 

24,474

2018

 

 

20,633

2019

 

 

9,931

2020

 

 

3,517

Thereafter

 

 

27,943

 

Total

$

152,072

 

 

 

 

 

 

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the three months ended June 30, 2015 and 2014 were approximately $1.9 million and $1.7 million, respectively, and approximately $3.8 million and $3.4 million for the six months ended June 30, 2015 and 2014, respectively.

 

Future minimum lease commitments under non-cancellable operating leases at June 30, 2015 were as follows:

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2015

 

$

3,792

2016

 

 

6,269

2017

 

 

6,137

2018

 

 

5,233

2019

 

 

4,306

2020

 

 

4,259

Thereafter

 

 

4,687

 

Total

$

34,683

 

 

 

 

 

 

Note 10. Income taxes

 

The effective income tax rates were 37.0 percent and 37.5 percent for the three months ended June 30, 2015 and 2014, respectively, and 37.1 percent and 37.7 percent for the six months ended June 30, 2015 and 2014, respectively. Total income tax expense for the three and six months ended June 30, 2015 and 2014 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.  

18 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 11. Related party transactions

 

The following table summarizes charges incurred with and payments made to related parties and reported in the Company’s consolidated statements of operations for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

 

 

June 30,

 

June 30,

(in thousands)

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts paid to a partnership in which a director has an ownership interest (a)

 

$

1,403

 

$

3,253

 

$

3,097

 

$

6,055

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Royalties paid to a director and certain officers of the Company (b)

 

$

32

 

$

60

 

$

555

 

$

157

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)   Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

 

(b)   Amounts include revenue interests, overriding royalty interests, and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an officer.

 

 

19 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 12. Net income (loss) per share

 

The Company uses the two-class method of calculating net income (loss) per share because certain of the Company’s unvested share-based awards qualify as participating securities.

 

The following table reconciles the Company’s income (loss) from operations and income (loss) attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income (loss) per share amounts for the three and six months ended June 30, 2015 and 2014, respectively, under the two-class method:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

June 30,

 

June 30,

(in thousands, except per share amounts)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) as reported

 

$

(120,483)

 

$

11,769

 

$

(112,971)

 

$

103,076

Participating basic earnings

 

 

-

 

 

(131)

 

 

-

 

 

(1,174)

 

Basic income (loss) attributable to common stockholders

 

 

(120,483)

 

 

11,638

 

 

(112,971)

 

 

101,902

Reallocation of participating earnings

 

 

-

 

 

1

 

 

-

 

 

3

 

Diluted income (loss) attributable to common stockholders

 

$

(120,483)

 

$

11,639

 

$

(112,971)

 

$

101,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.02)

 

$

0.11

 

$

(0.97)

 

$

0.96

 

Diluted

 

$

(1.02)

 

$

0.11

 

$

(0.97)

 

$

0.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

June 30,

 

June 30,

(in thousands)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

  

 

 

 

  

 

 

 

 

Basic

  

117,637

 

107,733

 

116,502

 

105,852

 

 

Dilutive common stock options

  

-

 

107

 

-

 

115

 

 

Dilutive performance units

  

-

 

211

 

-

 

222

 

Diluted

  

117,637

 

108,051

  

116,502

 

106,189

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.

20 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 13. Stockholders’ equity

 

Public common stock offering. In March 2015, the Company issued 6.9 million shares of its common stock in a public offering at $107.49 per share and received net proceeds of approximately $741.5 million.

 

Note 14. Subsidiary guarantors

 

All of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances, including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

 

See Note 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors.

 

The following condensed consolidating balance sheets at June 30, 2015 and December 31, 2014, condensed consolidating statements of operations for the three and six months ended June 30, 2015 and 2014 and condensed consolidating statements of cash flows for the six months ended June 30, 2015 and 2014, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

21 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Condensed Consolidating Balance Sheet

June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

  

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

  

 

 

  

 

 

Accounts receivable - related parties

  

$

7,684,553

 

$

1,171,087

 

$

(8,855,640)

 

$

-

Other current assets

  

 

383,698

 

 

517,994

 

 

-

 

 

901,692

Oil and natural gas properties, net

  

 

-

 

 

10,830,298

 

 

-

 

 

10,830,298

Property and equipment, net

  

 

-

 

 

146,138

 

 

-

 

 

146,138

Investment in subsidiaries

  

 

4,046,002

 

 

-

 

 

(4,046,002)

 

 

-

Other long-term assets

  

 

157,340

 

 

118,508

 

 

-

 

 

275,848

 

Total assets

  

$

12,271,593

  

$

12,784,025

  

$

(12,901,642)

  

$

12,153,976

 

 

  

 

 

  

 

 

  

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

  

 

 

  

 

 

Accounts payable - related parties

  

$

1,171,087

 

$

7,684,553

 

$

(8,855,640)

 

$

-

Other current liabilities

  

 

186,222

 

 

912,907

 

 

-

 

 

1,099,129

Long-term debt

  

 

3,582,465

 

 

-

 

 

-

 

 

3,582,465

Other long-term liabilities

  

 

1,393,672

 

 

140,563

 

 

-

 

 

1,534,235

Equity

  

 

5,938,147

 

 

4,046,002

 

 

(4,046,002)

 

 

5,938,147

 

Total liabilities and equity

  

$

12,271,593

  

$

12,784,025

  

$

(12,901,642)

  

$

12,153,976

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Balance Sheet

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

 

 

 

  

 

 

Accounts receivable - related parties

  

$

6,670,744

 

$

1,201,950

 

$

(7,872,694)

 

$

-

Other current assets

  

 

569,545

 

 

618,851

 

 

-

 

 

1,188,396

Oil and natural gas properties, net

  

 

-

 

 

10,076,878

 

 

-

 

 

10,076,878

Property and equipment, net

  

 

-

 

 

129,136

 

 

-

 

 

129,136

Investment in subsidiaries

  

 

4,085,045

 

 

-

 

 

(4,085,045)

 

 

-

Other long-term assets

  

 

330,792

 

 

74,761

 

 

-

 

 

405,553

 

Total assets

  

$

11,656,126

  

$

12,101,576

 

$

(11,957,739)

  

$

11,799,963

 

 

  

 

 

  

 

 

 

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

 

 

 

  

 

 

Accounts payable - related parties

  

$

1,201,950

 

$

6,670,744

 

$

(7,872,694)

 

$

-

Other current liabilities

  

 

217,884

 

 

1,209,309

 

 

-

 

 

1,427,193

Long-term debt

  

 

3,517,320

 

 

-

 

 

-

 

 

3,517,320

Other long-term liabilities

  

 

1,438,184

 

 

136,478

 

 

-

 

 

1,574,662

Equity

  

 

5,280,788

 

 

4,085,045

 

 

(4,085,045)

 

 

5,280,788

 

Total liabilities and equity

  

$

11,656,126

  

$

12,101,576

 

$

(11,957,739)

  

$

11,799,963

 

 

 

 

 

 

 

 

 

 

 

 

 

 

22 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

537,425

 

$

-

 

$

537,425

Total operating costs and expenses

  

 

(148,039)

 

 

(521,417)

 

 

-

 

 

(669,456)

 

Income (loss) from operations

  

 

(148,039)

 

 

16,008

 

 

-

 

 

(132,031)

Interest expense

  

 

(53,482)

 

 

-

 

 

-

 

 

(53,482)

Other, net

  

 

10,330

 

 

(5,678)

 

 

(10,330)

 

 

(5,678)

 

Income (loss) before income taxes

  

 

(191,191)

 

 

10,330

 

 

(10,330)

 

 

(191,191)

Income tax benefit

  

 

70,708

 

 

-

 

 

-

 

 

70,708

 

Net income (loss)

  

$

(120,483)

 

$

10,330

 

$

(10,330)

 

$

(120,483)

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

704,702

 

$

-

 

$

704,702

Total operating costs and expenses

  

 

(165,326)

 

 

(451,315)

 

 

-

 

 

(616,641)

 

Income (loss) from operations

  

 

(165,326)

 

 

253,387

 

 

-

 

 

88,061

Interest expense

  

 

(55,388)

 

 

-

 

 

-

 

 

(55,388)

Loss on extinguishment of debt

  

 

(4,316)

 

 

-

 

 

-

 

 

(4,316)

Other, net

  

 

243,858

 

 

(9,530)

 

 

(243,857)

 

 

(9,529)

 

Income before income taxes

  

 

18,828

 

 

243,857

 

 

(243,857)

 

 

18,828

Income tax expense

  

 

(7,059)

 

 

-

 

 

-

 

 

(7,059)

 

Net income

  

$

11,769

 

$

243,857

 

$

(243,857)

 

$

11,769

 

 

 

 

 

 

 

 

 

 

 

 

 

 

23 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

950,947

 

$

-

 

$

950,947

Total operating costs and expenses

  

 

(33,435)

 

 

(979,971)

 

 

-

 

 

(1,013,406)

 

Loss from operations

  

 

(33,435)

 

 

(29,024)

 

 

-

 

 

(62,459)

Interest expense

  

 

(107,051)

 

 

-

 

 

-

 

 

(107,051)

Other, net

  

 

(39,043)

 

 

(10,019)

 

 

39,043

 

 

(10,019)

 

Loss before income taxes

  

 

(179,529)

 

 

(39,043)

 

 

39,043

 

 

(179,529)

Income tax benefit

  

 

66,558

 

 

-

 

 

-

 

 

66,558

 

Net loss

  

$

(112,971)

 

$

(39,043)

 

$

39,043

 

$

(112,971)

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

1,365,661

 

$

-

 

$

1,365,661

Total operating costs and expenses

  

 

(201,479)

 

 

(873,889)

 

 

-

 

 

(1,075,368)

 

Income (loss) from operations

  

 

(201,479)

 

 

491,772

 

 

-

 

 

290,293

Interest expense

  

 

(111,523)

 

 

-

 

 

-

 

 

(111,523)

Loss on extinguishment of debt

  

 

(4,316)

 

 

-

 

 

-

 

 

(4,316)

Other, net

  

 

482,784

 

 

(8,989)

 

 

(482,783)

 

 

(8,988)

 

Income before income taxes

  

 

165,466

 

 

482,783

 

 

(482,783)

 

 

165,466

Income tax expense

  

 

(62,390)

 

 

-

 

 

-

 

 

(62,390)

 

Net income

  

$

103,076

 

$

482,783

 

$

(482,783)

 

$

103,076

 

 

 

 

 

 

 

 

 

 

 

 

 

 

24 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

  

$

(1,085,293)

 

$

1,574,227

 

$

-

 

$

488,934

Net cash flows provided by (used in) investing activities

 

 

279,408

 

 

(1,563,597)

 

 

-

 

 

(1,284,189)

Net cash flows provided by (used in) financing activities

  

 

805,885

 

 

(10,371)

 

 

-

 

 

795,514

 

Net increase in cash and cash equivalents

  

 

-

 

 

259

 

 

-

 

 

259

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

21

 

 

-

 

 

21

 

Cash and cash equivalents at end of period

  

$

-

 

$

280

 

$

-

 

$

280

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 





Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

 

$

(631,569)

 

$

1,486,297

 

$

-

  

$

854,728

Net cash flows used in investing activities

  

 

(40,891)

 

 

(1,084,112)

 

 

-

  

 

(1,125,003)

Net cash flows provided by (used in) financing activities

  

 

672,460

 

 

(36,718)

 

 

-

  

 

635,742

 

Net increase in cash and cash equivalents

  

 

-

 

 

365,467

 

 

-

 

 

365,467

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

21

 

 

-

 

 

21

 

Cash and cash equivalents at end of period

  

$

-

 

$

365,488

 

$

-

 

$

365,488

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

25 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 15. Subsequent events

 

New commodity derivative contracts.  After June 30, 2015, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

450,000

 

675,000

 

1,125,000

 

 

Price per Bbl

 

 

 

 

$

49.12

$

49.12

$

49.12

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

950,000

 

750,000

 

750,000

 

750,000

 

3,200,000

 

 

Price per Bbl

$

53.43

$

53.62

$

53.62

$

53.62

$

53.56

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

360,000

 

360,000

 

-

 

-

 

720,000

 

 

Price per Bbl

$

56.63

$

56.63

$

-

$

-

$

56.63

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

305,000

 

460,000

 

765,000

 

 

Price per Bbl

 

 

 

 

$

0.22

$

0.22

$

0.22

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

-

 

-

 

184,000

 

-

 

184,000

 

 

Price per Bbl

$

-

$

-

$

(0.70)

$

-

$

(0.70)

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

720,000

 

728,000

 

-

 

-

 

1,448,000

 

 

Price per Bbl

$

(0.96)

$

(0.96)

$

-

$

-

$

(0.96)

Natural Gas Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

910,000

 

910,000

 

920,000

 

920,000

 

3,660,000

 

 

Price per MMBtu

$

3.14

$

3.14

$

3.14

$

3.14

$

3.14

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate (“WTI”) monthly average futures price.

 

(b)

The basis differential price is between Midland – WTI and Cushing – WTI.

(c)

The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

26 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2015

Unaudited

 

Note 16. Supplementary information

 

Capitalized costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

December 31,

(in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Oil and natural gas properties:

 

 

 

 

 

 

 

Proved

 

$

14,232,112

 

$

12,795,970

 

Unproved

 

 

951,201

 

 

1,071,861

 

Less: accumulated depletion

 

 

(4,353,015)

 

 

(3,790,953)

 

 

Net capitalized costs for oil and natural gas properties

 

$

10,830,298

 

$

10,076,878

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs incurred for oil and natural gas producing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

June 30,

 

June 30,

(in thousands)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

  

 

 

 

 

 

 

Proved

  

$

2,243

 

$

2,137

 

$

2,243

 

$

22,627

 

Unproved

  

 

18,037

 

 

11,382

 

 

34,050

 

 

36,070

Exploration

  

 

343,051

 

 

342,424

 

 

772,220

 

 

666,921

Development

  

 

221,410

 

 

193,163

 

 

523,154

 

 

404,842

 

Total costs incurred for oil and natural gas properties

  

$

584,741

 

$

549,106

  

$

1,331,667

 

$

1,130,460

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

27 


     

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes.

 

Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements.”

 

Overview

 

We are an independent oil and natural gas company engaged in the acquisition, development and exploration of producing oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We refer to our three core operating areas as the (i) New Mexico Shelf, where we primarily target the Yeso formation with horizontal and vertical development, (ii) Delaware Basin, where we use horizontal drilling to target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale formation and (iii) Texas Permian in the Midland Basin, where we target the Wolfcamp and Spraberry formations with horizontal and vertical development. Oil comprised 58.1 percent of our 637.2 MMBoe of estimated proved reserves at December 31, 2014 and 67.6 percent of our 25.3 MMBoe of production for the six months ended June 30, 2015. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 92.3 percent of our proved developed producing PV-10 and 79.5 percent of our approximately 7,208 gross wells at December 31, 2014. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

 

Financial and Operating Performance

 

Our financial and operating performance for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, included the following highlights:

 

·         Net loss was $(113.0) million ($(0.97) per diluted share) for the first six months of 2015, as compared to net income of $103.1 million ($0.96 per diluted share) during the six months ended June 30, 2014. The decrease in net income was primarily due to:

 

       $414.8 million decrease in oil and natural gas revenues as a result of a 48 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities), partially offset by a 34 percent increase in production;  

 

       $113.2 million increase in depreciation, depletion and amortization expense, primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015; and

 

       $22.4 million increase in general and administrative expense due to an increase in the number of employees and related personnel expenses to manage our increased drilling and exploration activities during the second half of 2014;

 

partially offset by:

 

       $168.2 million decrease in the loss on derivatives not designated as hedges during the six months ended June 30, 2015, as compared to the same period in 2014;

 

       $129.0 million change in our income tax provision due to the decrease in income before income taxes; and

 

       $35.9 million decrease in exploration and abandonment expense due primarily to more exploratory dry hole costs and leasehold abandonments in 2014 as compared to 2015.

 

 

28 


     

·         Average daily sales volumes increased by 34 percent to 139,826 Boe per day during the first six months of 2015, as compared to 104,729 Boe per day during the first six months of 2014. The increase is primarily attributable to our successful drilling and completion efforts during 2014 and 2015.

 

·         Net cash provided by operating activities decreased by approximately $365.8 million to $488.9 million for the first six months of 2015, as compared to $854.7 million in the first six months of 2014, primarily due to a decrease in oil and natural gas revenues offset partially by positive variances in working capital changes.

 

·         Long-term debt increased by approximately $65.1 million during the first six months of 2015, which, along with proceeds from our March 2015 equity offering, funded our acquisitions and capital expenditures related to our drilling program.

 

Commodity Prices

 

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and natural gas liquids, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil, natural gas and natural gas liquids, include:

 

·         continuing economic uncertainty worldwide;

 

·         political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;

 

·         the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil prices and production controls;

 

·         technological advances affecting energy consumption and energy supply;

 

·         the effect of energy conservation efforts;

 

·         the price and availability of alternative fuels;

 

·         domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

 

·         the level of global inventories;

 

·         the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing and gathering and refining capacity;

 

·         risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas and the level of commodity inventory in the Permian Basin;

 

·         the quality of the oil we produce;

 

·         the overall global demand for oil natural gas and natural gas liquids;

 

·         the domestic and foreign supply of oil, natural gas and natural gas liquids; and

 

·         overall North American oil and natural gas supply and demand fundamentals, including:

 

       the United States economy impact,

 

       weather conditions, and

 

       the potential for liquefied natural gas deliveries to and exports from the United States.

 

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 7 and 15 of the Condensed Notes to

29 


     

Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at June 30, 2015 and additional derivative contracts entered into subsequent to June 30, 2015, respectively.

 

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were significantly lower during the comparable periods of 2015 measured against 2014. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and six months ended June 30, 2015 and 2014, as well as the high and low NYMEX prices for the same periods:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

  

 

 

 

June 30,

 

June 30,

 

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl)

  

$

57.80

 

$

103.07

  

$

53.33

 

$

100.85

 

Natural gas (MMBtu)

  

$

2.74

 

$

4.58

  

$

2.78

 

$

4.65

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

High and Low NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

  

$

61.43

 

$

107.26

  

$

61.43

 

$

107.26

 

 

Low

  

$

49.14

 

$

99.42

  

$

43.46

 

$

91.66

 

Natural gas (MMBtu):

  

 

 

 

 

 

  

 

 

 

 

 

 

 

High

  

$

3.02

 

$

4.83

  

$

3.23

 

$

6.15

 

 

Low

  

$

2.49

 

$

4.28

  

$

2.49

 

$

4.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

 

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $56.96 and $47.39 per Bbl and $2.92 and $2.69 per MMBtu, respectively, during the period from June 30, 2015 to July 27, 2015. At July 27, 2015, the NYMEX oil price and NYMEX natural gas price were $47.39 per Bbl and $2.79 per MMBtu, respectively.

 

Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the first half of 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $18.67 per Bbl during the three months ended June 30, 2015, as compared to $36.54 per Bbl during the three months ended June 30, 2014 and $18.99 per Bbl during the six months ended June 30, 2015, as compared to $38.71 per Bbl during the six months ended June 30, 2014.

30 


     

Recent Events

 

Common stock offering. In March 2015, we issued in a public offering approximately 6.9 million shares of our common stock at $107.49 per share, and we received net proceeds of approximately $741.5 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

 

Derivative Financial Instruments

 

Derivative financial instrument exposure. At June 30, 2015, the fair value of our financial derivatives was a net asset of $441.2 million. All of our counterparties to these financial derivatives are parties or affiliates of parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party or its affiliates.

 

New commodity derivative contracts. After June 30, 2015, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of our estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

450,000

 

675,000

 

1,125,000

 

 

Price per Bbl

 

 

 

 

$

49.12

$

49.12

$

49.12

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

950,000

 

750,000

 

750,000

 

750,000

 

3,200,000

 

 

Price per Bbl

$

53.43

$

53.62

$

53.62

$

53.62

$

53.56

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

360,000

 

360,000

 

-

 

-

 

720,000

 

 

Price per Bbl

$

56.63

$

56.63

$

-

$

-

$

56.63

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

305,000

 

460,000

 

765,000

 

 

Price per Bbl

 

 

 

 

$

0.22

$

0.22

$

0.22

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

-

 

-

 

184,000

 

-

 

184,000

 

 

Price per Bbl

$

-

$

-

$

(0.70)

$

-

$

(0.70)

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

720,000

 

728,000

 

-

 

-

 

1,448,000

 

 

Price per Bbl

$

(0.96)

$

(0.96)

$

-

$

-

$

(0.96)

Natural Gas Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

910,000

 

910,000

 

920,000

 

920,000

 

3,660,000

 

 

Price per MMBtu

$

3.14

$

3.14

$

3.14

$

3.14

$

3.14

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate (“WTI”) monthly average futures price.

 

(b)

The basis differential price is between Midland – WTI and Cushing – WTI.

(c)

The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31 


     

Results of Operations

 

The following table sets forth summary information concerning our production and operating data for the three and six months ended June 30, 2015 and 2014. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

  

 

 

 

 

  

June 30,

 

June 30,

 

 

 

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and operating data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

  

 

9,031

 

 

6,229

 

 

17,097

 

 

12,075

 

 

Natural gas (MMcf)

  

 

26,283

 

 

21,485

 

 

49,268

 

 

41,285

 

 

Total (MBoe)

  

 

13,412

 

 

9,810

 

 

25,308

 

 

18,956

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbl)

  

 

99,242

 

 

68,451

 

 

94,459

 

 

66,713

 

 

Natural gas (Mcf)

  

 

288,824

 

 

236,099

 

 

272,199

 

 

228,094

 

 

Total (Boe)

  

 

147,379

 

 

107,801

 

 

139,826

 

 

104,729

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 Average prices:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, without derivatives (Bbl)

  

$

52.14

 

$

93.24

 

$

47.99

 

$

92.81

 

 

Oil, with derivatives (Bbl) (a)

  

$

63.56

 

$

89.29

 

$

63.39

 

$

89.96

 

 

Natural gas, without derivatives (Mcf)

  

$

2.53

 

$

5.77

 

$

2.65

 

$

5.94

 

 

Natural gas, with derivatives (Mcf) (a)

  

$

2.88

 

$

5.70

 

$

2.97

 

$

5.78

 

 

Total, without derivatives (Boe)

  

$

40.07

 

$

71.84

 

$

37.57

 

$

72.04

 

 

Total, with derivatives (Boe) (a)

  

$

48.44

 

$

69.18

 

$

48.62

 

$

69.89

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

Operating costs and expenses per Boe:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses and workover costs

  

$

7.30

 

$

8.15

 

$

7.46

 

$

8.11

 

 

Oil and natural gas taxes

  

$

3.30

 

$

5.61

 

$

3.12

 

$

5.70

 

 

Depreciation, depletion and amortization

  

$

22.72

 

$

24.20

 

$

22.60

 

$

24.21

 

 

General and administrative

  

$

4.54

 

$

5.05

 

$

4.73

 

$

5.13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Includes the effect of cash receipts from (payments on) derivatives not designated as hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

  

 

 

  

June 30,

 

June 30,

 

 

(in thousands)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash receipts from (payments on) derivatives not designated as hedges:

  

 

 

 

 

 

 

 

 

Oil derivatives

 

$

103,129

 

$

(24,569)

 

$

263,315

 

$

(34,338)

 

 

 

Natural gas derivatives

 

 

9,123

 

 

(1,485)

 

 

16,093

 

 

(6,553)

 

 

 

 

Total

 

$

112,252

  

$

(26,054)

  

$

279,408

  

$

(40,891)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

32 


     

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

 

 

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $537.4 million for the three months ended June 30, 2015, a decrease of $167.3 million (24 percent) from $704.7 million for the three months ended June 30, 2014. This decrease was primarily due to the decrease in realized oil and natural gas prices, partially offset by increased production due to our successful drilling efforts during 2014 and 2015. Specific factors affecting oil and natural gas revenues include the following:

 

·         total oil production was 9,031 MBbl  for the three months ended June 30, 2015, an increase  of 2,802 MBbl  (45 percent) from 6,229 MBbl  for the three months ended June 30, 2014

 

·         average realized oil price (excluding the effects of derivative activities) was $52.14 per Bbl during the three months ended June 30, 2015, a decrease of 44 percent  from $93.24  per Bbl during the three months ended June 30, 2014. For the three months ended June 30, 2015 and 2014, we realized approximately 90.2 percent and 90.5 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the three months ended June 30, 2015 and 2014, the market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $0.60 per Bbl and $8.37 per Bbl, respectively;

 

·         total natural gas production was 26,283 MMcf  for the three months ended June 30, 2015, an increase  of 4,798 MMcf  (22 percent) from 21,485 MMcf  for the three months ended June 30, 2014; and

 

·         average realized natural gas price (excluding the effects of derivative activities) was $2.53 per Mcf during the three months ended June 30, 2015, a decrease of 56 percent  from $5.77 per Mcf during the three months ended June 30, 2014. For the three months ended June 30, 2015 and 2014, we realized approximately 92.3 percent and 126.0 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the three months ended June 30, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $18.67 per Bbl, as compared to $36.54 per Bbl during the three months ended June 30, 2014.

33 


     

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

 

Three Months Ended June 30,

 

 

 

 

 

2015

 

 

2014

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

92,059

 

$

6.86

 

$

76,310

 

$

7.78

Taxes:

  

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem

  

 

6,308

 

 

0.47

 

 

5,388

 

 

0.55

 

Production

  

 

38,012

 

 

2.83

 

 

49,636

 

 

5.06

Workover costs

  

 

5,886

 

 

0.44

 

 

3,610

 

 

0.37

 

 

Total oil and natural gas production expenses

  

$

142,265

 

$

10.60

  

$

134,944

 

$

13.76

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are related to commodity prices.

 

Lease operating expenses were $92.1 million ($6.86 per Boe) for the three months ended June 30, 2015, which was an increase of $15.8 million (21 percent) from $76.3 million ($7.78 per Boe) for the three months ended June 30, 2014. The increase in lease operating expenses was due to increased production associated with our wells successfully drilled and completed in 2014 and 2015. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies resulting in higher volume wells successfully drilled and completed in the second half of 2014 and 2015.

 

Production taxes per unit of production were $2.83 per Boe during the three months ended June 30, 2015, a decrease of 44 percent from $5.06 per Boe during the three months ended June 30, 2014. The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 44 percent.

 

Workover expenses were approximately $5.9 million and $3.6 million for the three months ended June 30, 2015 and 2014, respectively. The increase related primarily to workovers performed on saltwater disposal systems during 2015.

34 


     

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

  

 

June 30,

(in thousands)

  

2015

 

2014

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

2,054

 

$

10,143

Exploratory dry hole costs

  

 

8,208

 

 

6,758

Leasehold abandonments

  

 

1,444

 

 

11,193

Other

 

 

314

 

 

194

 

Total exploration and abandonments

  

$

12,020

  

$

28,288

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis. During the three months ended June 30, 2014, we acquired geological and geophysical data related to our northern Delaware Basin acreage.

 

Our exploratory dry hole costs during the three months ended June 30, 2015 were primarily related to an uneconomic well in our Delaware Basin area that was attempting to establish production in a different zone. Our exploratory dry hole costs during the three months ended June 30, 2014 were primarily related to (i) partial expensing of an unsuccessful deeper lateral zone in our Delaware Basin area and (ii) expensing an unsuccessful well drilled to test the outer limits of our Delaware Basin acreage.

 

For the three months ended June 30, 2015 and 2014, we recorded approximately $1.4 million and $11.2 million of leasehold abandonments, respectively.

 

Depreciation, depletion and amortization expense.  The following table provides components of our depreciation, depletion and amortization expense for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

 

 

2015

 

2014

 

 

 

 

 

Per

 

 

 

Per

(in thousands, except per unit amounts)

 

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

 

$

299,812

 

$

22.35

 

$

232,741

 

$

23.72

Depreciation of other property and equipment

 

 

4,624

 

 

0.34

 

 

4,338

 

 

0.44

Amortization of intangible assets - operating rights

 

 

366

 

 

0.03

 

 

366

 

 

0.04

 

Total depletion, depreciation and amortization

 

$

304,802

 

$

22.72

 

$

237,445

 

$

24.20

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil price used to estimate proved oil reserves at period end

 

$

68.17

 

 

 

 

$

96.75

 

 

 

Natural gas price used to estimate proved natural gas reserves at period end

 

$

3.39

 

 

 

 

$

4.10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties was $299.8 million ($22.35 per Boe) for the three months ended June 30, 2015, an increase of $67.1 million (29 percent) from $232.7 million ($23.72 per Boe) for the three months ended June 30, 2014. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015. The decrease in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil and natural gas properties due to a non-cash impairment charge of approximately $431.7 million recorded in the fourth quarter of 2014 and increased reserves supported by (i) one or more reliable technologies and (ii) our successful exploratory drilling program, partially offset by lower commodity prices.

 

The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items as a result of our increased number of employees.

35 


     

 

General and administrative expenses.  The following table provides components of our general and administrative expenses for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

51,847

 

$

3.87

 

$

45,618

 

$

4.65

Non-cash stock-based compensation

  

 

15,450

 

 

1.15

 

 

9,775

 

 

1.00

Less: Third-party operating fee reimbursements

  

 

(6,374)

 

 

(0.48)

 

 

(5,858)

 

 

(0.60)

 

Total general and administrative expenses

  

$

60,923

 

$

4.54

  

$

49,535

 

$

5.05

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses were approximately $60.9 million ($4.54 per Boe) for the three months ended June 30, 2015, an increase of $11.4 million (23 percent) from $49.5 million ($5.05 per Boe) for the three months ended June 30, 2014. The increase in cash general and administrative expenses and non-cash stock-based compensation was primarily due to an increase in the number of employees and related personnel expenses in order to manage our increased activities directly related to our increased drilling and exploration activities in the second half of 2014. During the first half of 2015, we began to slow both our activity and hiring rate. The decrease in total general and administrative expenses per Boe was primarily due to increased production from our wells successfully drilled and completed in 2014 and 2015, partially offset by an increase in the number of employees and related personnel expenses in order to manage our activities, coupled with increasing salaries in 2014 due to the highly competitive labor market.

 

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $6.4 million and $5.9 million during the three months ended June 30, 2015 and 2014, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements was primarily due to increased reimbursements attributable to more wells operated as a result of continued drilling activity.

36 


     

Loss on derivatives not designated as hedges.  The following table sets forth the loss on derivatives not designated as hedges for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

Loss on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

Oil derivatives

 

$

(146,549)

 

$

(163,655)

 

 

Natural gas derivatives

 

 

(850)

 

 

(1,052)

 

 

 

Total

 

$

(147,399)

 

$

(164,707)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents our cash receipts from (payments on) derivatives for the three months ended June 30, 2015 and 2014:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

Cash receipts from (payments on) derivatives not designated as hedges:

 

 

 

 

 

Oil derivatives

 

$

103,129

 

$

(24,569)

 

 

Natural gas derivatives

 

  

9,123

 

  

(1,485)

 

 

 

Total

 

$

112,252

 

$

(26,054)

 

 

 

 

 

 

 

 

 

 

 

 

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

 

Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

Three Months Ended

 

 

 

June 30,

(dollars in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

 

Interest expense

  

$

53,482

 

$

55,388

Capitalized interest

 

 

1,179

 

 

-

 

Interest expense, excluding impact of capitalized interest

 

$

54,661

 

$

55,388

 

  

 

 

 

 

 

Weighted average interest rate - credit facility

 

 

3.0%

 

 

2.4%

Weighted average interest rate - senior notes

 

 

5.9%

 

 

5.9%

 

Total weighted average interest rate

  

 

5.8%

 

 

5.7%

 

 

 

 

 

 

 

 

Weighted average credit facility balance

  

$

156,340

 

$

247,552

Weighted average senior notes balance

  

 

3,350,000

 

 

3,350,000

 

Total weighted average debt balance

  

$

3,506,340

 

$

3,597,552

 

 

 

 

 

 

 

 

 

The decrease in the weighted average debt balance for the three months ended June 30, 2015 as compared to the corresponding period in 2014 was due to the repayment of our credit facility using a portion of the proceeds from our March 2015 equity offering. The decrease in interest expense was due to an overall decrease in the weighted average debt balance, partially offset by a higher weighted average interest rate on our credit facility.

37 


     

Loss on extinguishment of debt.  In May 2014, we amended and restated our credit facility. We recorded a loss on extinguishment of debt of $4.3 million for the three months ended June 30, 2014,  representing the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

 

Income tax provisions.  We recorded an income tax benefit of $70.7 million and income tax expense of $7.1 million for the three months ended June 30, 2015 and 2014, respectively. The effective income tax rates for the three months ended June 30, 2015 and 2014 were 37.0 percent and 37.5 percent, respectively.

38 


     

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

 

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $950.9 million for the six months ended June 30, 2015, a decrease of $414.8 million (30 percent) from $1,365.7 million for the six months ended June 30, 2014. This decrease was primarily due to a decrease in realized oil and natural gas prices, offset partially by increased production due to our successful drilling efforts during 2014 and 2015. Specific factors affecting oil and natural gas revenues include the following:

 

·         total oil production was 17,097 MBbl  for the six months ended June 30, 2015, an increase  of 5,022 MBbl  (42 percent) from 12,075 MBbl  for the six months ended June 30, 2014

 

·         average realized oil price (excluding the effects of derivative activities) was $47.99 per Bbl during the six months ended June 30, 2015, a decrease of 48 percent  from $92.81  per Bbl during the six months ended June 30, 2014. For the six months ended June 30, 2015 and 2014, we realized approximately 90.0 percent and 92.0 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the six months ended June 30, 2015 and 2014, the market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $1.29 per Bbl and $5.94 per Bbl, respectively;

 

·         total natural gas production was 49,268 MMcf  for the six months ended June 30, 2015, an increase  of 7,983 MMcf  (19 percent) from 41,285 MMcf  for the six months ended June 30, 2014; and

 

·         average realized natural gas price (excluding the effects of derivative activities) was $2.65 per Mcf during the six months ended June 30, 2015, a decrease of 55 percent  from $5.94 per Mcf during the six months ended June 30, 2014. For the six months ended June 30, 2015 and 2014, we realized approximately 95.3 percent and 127.7 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the six months ended June 30, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $18.99 per Bbl, as compared to $38.71 per Bbl during the six months ended June 30, 2014.

39 


     

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

Six Months Ended June 30,

 

 

 

 

2015

 

2014

 

 

 

 

 

 

 

 

Per

 

 

 

 

 

Per

(in thousands, except per unit amounts)

  

 

Amount

 

 

Boe

 

 

Amount

 

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

175,717

 

$

6.94

 

$

146,503

 

$

7.73

Taxes:

  

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem

  

 

11,563

 

 

0.46

 

 

11,079

 

 

0.58

 

Production

  

 

67,423

 

 

2.66

 

 

97,058

 

 

5.12

Workover costs

  

 

13,097

 

 

0.52

 

 

7,228

 

 

0.38

 

 

Total oil and natural gas production expenses

  

$

267,800

 

$

10.58

  

$

261,868

 

$

13.81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are related to commodity prices.

 

Lease operating expenses were $175.7 million ($6.94 per Boe) for the six months ended June 30, 2015, which was an increase of $29.2 million (20 percent) from $146.5 million ($7.73 per Boe) for the six months ended June 30, 2014. The increase in lease operating expenses was due to increased production associated with our wells successfully drilled and completed in 2014 and 2015. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies resulting in higher volume wells successfully drilled and completed in the second half of 2014 and 2015.

 

Production taxes per unit of production were $2.66 per Boe during the six months ended June 30, 2015, a decrease of 48 percent from $5.12 per Boe during the six months ended June 30, 2014. The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 48 percent.

 

Workover expenses were approximately $13.1 million and $7.2 million for the six months ended June 30, 2015 and 2014, respectively. The increase related primarily to workovers performed on saltwater disposal systems during 2015.

40 


     

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

Six Months Ended

 

 

 

June 30,

(in thousands)

  

2015

 

2014

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

3,486

 

$

11,759

Exploratory dry hole costs

  

 

8,989

 

 

26,530

Leasehold abandonments

 

 

3,363

 

 

15,138

Other

  

 

1,937

 

 

236

 

Total exploration and abandonments

  

$

17,775

  

$

53,663

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis. During the six months ended June 30, 2014, we acquired geological and geophysical data related to our northern Delaware Basin acreage.

 

Our exploratory dry hole costs during the six months ended June 30, 2015 were primarily related to (i) an uneconomic well in our Delaware Basin area that was attempting to establish production in a different zone and (ii) expensing an unsuccessful well, which we did not operate, that was located in our New Mexico Shelf area. Our exploratory dry hole costs during the six months ended June 30, 2014 were primarily related to (i) partial expensing of unsuccessful horizontal laterals on two wells in the Delaware Basin, (ii) expensing three unsuccessful wells drilled to test the outer limits of our Delaware Basin acreage and (iii) an unsuccessful horizontal lateral in the New Mexico Shelf area.  

 

For the six  months ended June 30, 2015 and 2014, we recorded approximately $3.4 million and $15.1 million of leasehold abandonments, respectively.

 

Depreciation, depletion and amortization expense.  The following table provides components of our depreciation, depletion and amortization expense for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

Six Months Ended June 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Per

 

 

 

 

 

Per

(in thousands, except per unit amounts)

  

 

Amount

 

 

Boe

 

 

Amount

 

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

  

$

562,092

  

$

22.21

  

$

449,548

  

$

23.72

Depreciation of other property and equipment

  

 

9,184

 

 

0.36

 

 

8,558

 

 

0.45

Amortization of intangible asset - operating rights

  

 

731

 

 

0.03

 

 

731

 

 

0.04

 

Total depletion, depreciation and amortization

  

$

572,007

  

$

22.60

  

$

458,837

  

$

24.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties was $562.1 million ($22.21 per Boe) for the six months ended June 30, 2015, an increase of $112.6 million (25 percent) from $449.5 million ($23.72 per Boe) for the six months ended June 30, 2014. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015. The decrease in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil and natural gas properties due to a non-cash impairment charge of approximately $431.7 million recorded in the fourth quarter of 2014 and increased reserves supported by (i) one or more reliable technologies and (ii) our successful exploratory drilling program, partially offset by lower commodity prices.

 

The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items as a result of our increased number of employees.

 

41 


     

General and administrative expenses.  The following table provides components of our general and administrative expenses for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

Six Months Ended June 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

101,517

 

$

4.01

 

$

87,084

 

$

4.59

Non-cash stock-based compensation

  

 

30,945

 

 

1.22

 

 

21,207

 

 

1.12

Less: Third-party operating fee reimbursements

  

 

(12,738)

 

 

(0.50)

 

 

(11,006)

 

 

(0.58)

 

Total general and administrative expenses

  

$

119,724

 

$

4.73

 

$

97,285

 

$

5.13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses were approximately $119.7 million ($4.73 per Boe) for the six months ended June 30, 2015, an increase of $22.4 million (23 percent) from $97.3 million ($5.13 per Boe) for the six months ended June 30, 2014. The increase in general and administrative expenses and non-cash stock-based compensation was primarily due to an increase in the number of employees and related personnel expenses in order to manage our increased activities directly related to our increased drilling and exploration activities in the second half of 2014. During the first half of 2015, we began to slow both our activity and hiring rate. The decrease in total general and administrative expenses per Boe was primarily due to increased production from our wells successfully drilled and completed in 2014 and 2015, partially offset by an increase in the number of employees and related personnel expenses in order to manage our activities, coupled with increasing salaries in 2014 due to the highly competitive labor market.

 

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $12.7 million and $11.0 million during the six months ended June 30, 2015 and 2014, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements was primarily due to increased reimbursements attributable to more wells operated as a result of continued drilling activity.

42 


     

Gain (loss) on derivatives not designated as hedges.  The following table sets forth the gain (loss) on derivatives not designated as hedges for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

 

 

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

Oil derivatives

 

$

(36,269)

 

$

(187,875)

 

 

Natural gas derivatives

 

 

4,210

 

 

(12,447)

 

 

 

Total

 

$

(32,059)

 

$

(200,322)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents our cash receipts from (payments on) derivatives for the six months ended June 30, 2015 and 2014:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

 

 

 

June 30,

 

(in thousands)

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

Cash receipts from (payments on) derivatives not designated as hedges:

 

 

 

 

 

Oil derivatives

 

$

263,315

 

$

(34,338)

 

 

Natural gas derivatives

 

  

16,093

 

  

(6,553)

 

 

 

Total

 

$

279,408

 

$

(40,891)

 

 

 

 

 

 

 

 

 

 

 

 

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

 

Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

 

June 30,

(dollars in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

 

Interest expense

  

$

107,051

 

$

111,523

Capitalized interest

 

 

2,389

 

 

-

 

Interest expense, excluding impact of capitalized interest

  

$

109,440

 

$

111,523

 

 

  

 

 

 

 

 

Weighted average interest rate - credit facility

 

 

2.6%

 

 

2.3%

Weighted average interest rate - senior notes

 

 

5.9%

 

 

5.9%

 

Total weighted average interest rate

  

 

5.8%

 

 

5.7%

 

 

 

 

 

 

 

 

Weighted average credit facility balance

 

 

204,168

 

 

265,827

Weighted average senior notes balance

 

 

3,350,000

 

 

3,350,000

 

Total weighted average debt balance

 

$

3,554,168

 

$

3,615,827

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The decrease in the weighted average debt balance for the six months ended June 30, 2015 as compared to the corresponding period in 2014 was due to the repayment of our credit facility using a portion of the proceeds from our March

43 


     

2015 equity offering. The decrease in interest expense was due to an overall decrease in the weighted average debt balance, partially offset by a higher weighted average interest rate on our credit facility.

 

Loss on extinguishment of debt.  In May 2014, we amended and restated our credit facility. We recorded a loss on extinguishment of debt of $4.3 million for the six months ended June 30, 2014, representing the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

 

Income tax provisions.  We recorded an income tax benefit of $66.6 million and income tax expense of $62.4 million for the six months ended June 30, 2015 and 2014, respectively. The effective income tax rates for the six months ended June 30, 2015 and 2014 were 37.1 percent and 37.7 percent, respectively.

44 


     

Capital Commitments, Capital Resources and Liquidity

 

Capital commitments. Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, midstream joint venture and other capital commitments, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our credit facility or proceeds from the disposition of assets or alternative financing sources, as discussed in “— Capital resources” below.

 

Oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the six months ended June 30, 2015 and 2014 totaled $1.3 billion and $1.1 billion, respectively. The increase in costs incurred was primarily due to our activity level in the first half of 2015. In addition, in an effort to generate greater fracture complexity and improved productivity for horizontal wells, our enhanced completion design generally utilizes more stages and proppant volumes. The primary reason for the differences in the costs incurred and cash flow expenditures was the timing of payments. The 2015 expenditures were funded in part from borrowings under our credit facility and proceeds from our equity offering in March 2015.

 

2015 capital budget. In January 2015, we announced our updated 2015 capital budget of approximately $2.0 billion, of which approximately 90 percent of our capital budget for drilling and completion costs will be dedicated to horizontal drilling opportunities. Our 2015 capital program is expected to continue focusing on drilling in the Delaware Basin. The capital spend related to our annual budget was weighted towards the first half of 2015 as we completed wells we commenced drilling in 2014. The 2015 capital budget, based on our current expectations of commodity prices and cost, will exceed our expected cash flow. We expect our cash flow, proceeds from our March 2015 equity offering and borrowings under our credit facility will be sufficient to fund our budgeted capital expenditure needs during 2015. However, if we experience sustained commodity prices lower than our forecasted pricing without sufficient costs reductions, we may adjust our capital budget to preserve our financial strength.

 

During the remainder of 2015, we plan to use our credit facility to fund such expenditures in excess of our cash flows. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third-parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans. 

 

Other than the customary purchase of leasehold acreage, our capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

 

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

 

 

June 30,

(in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

 

Proved

 

$

2,243

 

$

22,627

 

Unproved (a)

 

 

34,050

 

 

36,070

 

 

Total property acquisition costs

  

$

36,293

 

$

58,697

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Included in the unproved property acquisition costs above are budgeted leasehold acreage acquisitions of $29.8 million and $21.4 million for the six months ended June 30, 2015 and 2014, respectively.

 

 

 

 

 

 

 

 

 

 

45 


     

 

Contractual obligations.  Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, purchase obligations, employment agreements with executive officers, derivative liabilities, investment contributions related to Alpha Crude Connecter, LLC and other obligations. Since December 31, 2014, there have been no material changes in our contractual obligations. See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the six months ended June 30, 2015.

 

Off-balance sheet arrangements.  Currently, we do not have any material off-balance sheet arrangements.

 

Capital resources.  Our primary sources of liquidity have been cash flows generated from operating activities and cash settlements received from derivatives not designated as hedges, borrowings under our credit facility and proceeds from bond and equity offerings. We believe our 2015 expected capital expenditures will exceed our 2015 cash flow, and we have funded the difference with cash on hand, borrowings under our credit facility and proceeds from our equity offering in March 2015, and expect to continue to fund the difference with cash on hand and borrowings under our credit facility. We believe that we have adequate availability under our credit facility to fund any cash flow deficits.

 

The following table summarizes our changes in cash and cash equivalents for the six months ended June 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

  

 

Six Months Ended

 

 

 

 

June 30,

(in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

  

$

488,934

 

$

854,728

Net cash used in investing activities

  

 

(1,284,189)

 

 

(1,125,003)

Net cash provided by financing activities

  

 

795,514

 

 

635,742

 

Net increase in cash and cash equivalents

  

$

259

 

$

365,467

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow from operating activities. The decrease in operating cash flows during the six  months ended June 30, 2015 as compared to the same period in 2014 was primarily due to (i) a decrease in oil and natural gas revenues of approximately $414.8 million and (ii) a cash increase in general and administrative expense of approximately $12.7 million, offset in part by approximately $66.6 million of positive variances in operating assets and liabilities.

 

Our net cash provided by operating activities included an increase of approximately $38.9 million and a reduction of approximately $27.7 million for the six  months ended June 30, 2015 and 2014, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

 

Cash flow used in investing activities. During the six months ended June 30, 2015 and 2014, we invested approximately $1.5 billion and $1.1 billion, respectively, for capital expenditures on oil and natural gas properties. Also, cash flows used in investing activities increased during the six months ended June 30, 2015 as compared to the same period in 2014 related to (i) contributions to our equity method investment of approximately $45.0 million during the six months ended June 30, 2015 compared to $10.1 million during the six months ended June 30, 2014 and (ii) $26.1 million of investment in other property and equipment during the six months ended June 30, 2015 compared to $20.5 million during the comparative period of 2014, partially offset by 2015 settlements received on derivatives not designated as hedges of approximately $279.4 million during the six months ended June 30, 2015 compared to payments of approximately $40.9 million during the six months ended June 30, 2014.

 

Cash flow from financing activities. Net cash provided by financing activities was approximately $795.5 million and $635.7 million for the six  months ended June 30, 2015 and 2014, respectively. Below is a description of our financing activities:

46 


     

 

·         In March 2015, we issued shares of our common stock in a public offering and received net proceeds of approximately $741.5 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

 

·         During the first half of 2015, we had net borrowings on our credit facility of $66.5 million.

 

·         In May 2014, we issued shares of our common stock in a public offering and received net proceeds of approximately $932.5 million during the six months ended June 30, 2014. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes. 

 

·         During the first half of 2014, we had net payments on our credit facility of $250.0 million.

 

At June 30, 2015, we had unused commitments of approximately $2.3 billion based on bank commitments of $2.5 billion. The maturity date of the credit facility is May 9, 2019.

 

Advances on our amended and restated credit facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The amended and restated credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 125 to 225 basis points and 25 to 125 basis points, respectively, per annum depending on the utilization of the borrowing base. We pay commitment fees on the unused portion of the available commitment ranging from 30.0 to 37.5 basis points per annum, depending on utilization of the borrowing base. Subject to certain restrictions, with respect to our public debt ratings, the collateral securing the facility may be released.

 

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. Over the last three years, we have demonstrated our use of the capital markets by issuing common stock and senior unsecured debt. There are no assurances that we can access the capital markets to obtain additional funding, if needed, and at cost and terms that are favorable to us. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

 

Liquidity. Our principal sources of liquidity are cash on hand and available borrowing capacity under our credit facility. At June 30, 2015, we had $280,000 of cash on hand.

 

At June 30, 2015, commitments from our bank group totaled $2.5 billion. In April 2015, we amended our credit agreement to remove the current ratio financial covenant and reaffirm our borrowing base of $3.25 billion. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity. Upon a redetermination, our borrowing base could be substantially reduced.

 

Debt ratings We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba2” with a positive outlook. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. A reduction in our debt ratings could negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

 

Book capitalization and current ratio   Our book capitalization at June 30, 2015 was $9.5 billion, consisting of debt of $3.6 billion and stockholders’ equity of $5.9 billion. Our debt to book capitalization was 38 percent and 40  percent at June 30, 2015 and December 31, 2014, respectively. Our ratio of current assets to current liabilities was 0.82 to 1.0 at June 30, 2015 as compared to 0.83 to 1.0 at December 31, 2014.

 

Inflation and changes in prices.  Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs

47 


     

to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the six months ended June 30, 2015, we received an average of $47.99 per Bbl of oil and $2.65 per Mcf of natural gas before consideration of commodity derivative contracts compared to $92.81 per Bbl of oil and $5.94 per Mcf of natural gas in the six months ended June 30, 2014. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

48 


     

Critical Accounting Policies, Practices and Estimates

 

Our historical consolidated financial statements and related condensed notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.

 

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, valuation of financial derivative instruments and income taxes. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

 

There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2015. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the United States Securities and Exchange Commission (the “SEC”) on February 26, 2015.

 

Recent accounting pronouncements. In April 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest–Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” that requires debt issuance costs related to a recognized debt liability be presented as a direct deduction from the carrying amount of that debt liability. We currently present debt issuance costs on the balance sheet as an asset.

 

An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. We plan to early adopt this ASU on December 31, 2015. As of June 30, 2015, we had $45.6 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability.

 

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

 

The original effective date to apply ASU 2014-09 was for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. However, on July 9, 2015, the FASB voted to approve a one-year deferral of the effective date of this standard, which when formalized in an ASU will move the effective date to annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

  

49 


     

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2014.

 

We are exposed to a variety of market risks, including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at June 30, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

 

Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

 

Credit risk.  We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligations to us, we may, if circumstances dictate, require collateral in the future. In this manner, we could reduce credit risk.

 

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.  See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

 

Commodity price risk.  We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $10.00 per Bbl of oil and $1.00 per MMBtu of natural gas from the commodity prices at June 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase of

 

 

Decrease of

 

 

 

 

 

 

 

 

$10 per Bbl and

 

 

$10 per Bbl and

(in thousands)

 

$1 per MMBtu

 

 

$1 per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss):

 

 

 

 

 

 

Oil derivatives

$

(308,767)

 

$

308,767

 

Natural gas derivatives

 

(10,403)

 

 

10,403

 

 

Total

$

(319,170)

 

$

319,170

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

50 


     

At June 30, 2015, we had (i) oil price swaps that settle on a monthly basis covering future oil production from July 1, 2015 through June 30, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from July 1, 2015 to June 30, 2017. The average NYMEX oil price for the six months ended June 30, 2015 was $53.33 per Bbl. At July 27, 2015, the NYMEX oil price was $47.39 per Bbl.

 

At June 30, 2015, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from July 1, 2015 to December 31, 2015 and (ii) natural gas basis swaps covering our basis differential between the El Paso Permian delivery point and the NYMEX-Henry Hub delivery point from July 1, 2015 to December 31, 2015. The average NYMEX natural gas price for the six months ended June 30, 2015 was $2.78 per MMBtu. At July 27, 2015, the NYMEX natural gas price was $2.79 per MMBtu.

 

A decrease in the average forward NYMEX oil and natural gas prices below those at June 30, 2015, would increase the fair value asset of our commodity derivative contracts from their recorded balance at June 30, 2015. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential increase in our fair value asset would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at June 30, 2015 would decrease the fair value asset of our commodity derivative contracts from their recorded balance at June 30, 2015. The potential decrease in our fair value asset would be recorded in earnings as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

 

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during the six months ended June 30, 2015 for our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the six months ended June 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivative

 

 

 

 

 

 

 

 

Instruments

(in thousands)

Net Assets (Liabilities) (a)

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of contracts outstanding at December 31, 2014

 

$

752,700

 

 

Changes in fair values (b)

 

 

(32,059)

 

 

Contract maturities

 

 

(279,408)

 

Fair value of contracts outstanding at June 30, 2015

 

$

441,233

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Represents the fair values of open derivative contracts subject to market risk.

 

 

 

 

(b)

At inception, new derivative contracts entered into by us have no intrinsic value.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

 

Interest rate risk.  Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we may, in the future, enter into interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our borrowing base.

 

We had total indebtedness of $206.0 million outstanding under our credit facility at June 30, 2015. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $2.1 million.

51 


     

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at June 30, 2015 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting. There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

52 


     

PART II – OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

We are a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

  

 

Item 1A.  Risk Factors

 

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, under the headings “Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosure About Market Risk,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2014. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2014 are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

 

 

 

 

 

 

 

 

 

 

Period

 

Total number of shares withheld (a)

 

Average price per share

 

Total number of shares purchased as part of publicly announced plans

 

Maximum number of shares that may yet be purchased under the plan

 

 

 

 

 

 

 

 

 

 

 

April 1, 2015 - April 30, 2015

  

1,824

 

$

124.49

 

-

 

 

May 1, 2015 - May 31, 2015

  

1,184

 

$

117.36

 

-

 

 

June 1, 2015 - June 30, 2015

  

7,172

 

$

123.53

 

-

 

 

  

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees that arose upon the lapse of restrictions on restricted stock.

 

  

  

 

 

 

 

 

 

 

 

 

53 


     

Item 6.  Exhibits

 

 

 

 

Exhibit

 Number 

 

Exhibit

 

 

 

 

 

3.1

 

Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

 

 

3.2

 

Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).

 

 

4.1

 

 

Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

 

10.1

 

 

10.2

 

Concho Resources Inc. 2015 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2015, and incorporated herein by reference).

 

First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

 

 

 

31.1 (a)

 

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

31.2 (a)

 

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

32.1 (b)

 

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

32.2 (b)

 

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

101.INS (a)

 

XBRL Instance Document.

 

 

101.SCH (a)

 

XBRL Schema Document.

 

 

101.CAL (a)

 

XBRL Calculation Linkbase Document.

 

 

101.DEF (a)

 

XBRL Definition Linkbase Document.

 

 

101.LAB (a)

 

XBRL Labels Linkbase Document.

 

 

101.PRE (a)

 

XBRL Presentation Linkbase Document.

 

 

 

 

 

 

(a)  Filed herewith.

(b)  Furnished herewith.

  

54 


     

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

  

 

CONCHO RESOURCES INC.

 

 

 

 

 

Date:

July 30, 2015

 

By

/s/  Timothy A. Leach          

 

 

 

 

 

 

 

 

 

Timothy A. Leach

 

 

 

 

Director, Chairman of the Board of Directors, Chief Executive

 

 

 

 

Officer and President

 

 

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By

/s/  Darin G. Holderness

 

 

 

 

 

 

 

 

 

Darin G. Holderness

 

 

 

 

Senior Vice President, Chief Financial Officer and Treasurer

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By

/s/  Brenda R. Schroer

 

 

 

 

 

 

 

 

 

Brenda R. Schroer

 

 

 

 

Vice President and Chief Accounting Officer

 

 

 

 

(Principal Accounting Officer)

55 


     

EXHIBIT INDEX

 

 

 

 

 

Exhibit

 Number 

 

Exhibit

 

 

 

 

 

3.1

 

Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

 

 

3.2

 

Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).

 

 

4.1

 

 

Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

 

10.1

 

 

10.2

 

Concho Resources Inc. 2015 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2015, and incorporated herein by reference).

 

First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

 

 

 

31.1 (a)

 

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

31.2 (a)

 

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

32.1 (b)

 

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

32.2 (b)

 

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

101.INS (a)

 

XBRL Instance Document.

 

 

101.SCH (a)

 

XBRL Schema Document.

 

 

101.CAL (a)

 

XBRL Calculation Linkbase Document.

 

 

101.DEF (a)

 

XBRL Definition Linkbase Document.

 

 

101.LAB (a)

 

XBRL Labels Linkbase Document.

 

 

101.PRE (a)

 

XBRL Presentation Linkbase Document.

 

 

 

 

 

 

(a)  Filed herewith.

(b)  Furnished herewith.