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 September 30, 2014

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 November 4, 2014: 113,010,076 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

30

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

53

 

 

 

 

Item 4. Controls and Procedures

55

 

 

 

PART II – OTHER INFORMATION:

56

 

 

 

 

Item 1. Legal Proceedings

56

 

 

 

 

Item 1A. Risk Factors

56

 

 

 

 

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

56

 

 

 

 

Item 6. Exhibits  

57

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, 2013, 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 and risks related to hydraulic fracturing activities;

·         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;

·         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 our oil, natural gas liquids and natural gas and other processing and transportation considerations;

·         shortages of oilfield equipment, supplies, water, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

·         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 September 30, 2014 and December 31, 2013

1

 

 

Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013

2

 

 

Consolidated Statement of Stockholders’  Equity for the Nine Months Ended September 30, 2014

3

 

 

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013

4

 

 

Condensed Notes to Consolidated Financial Statements

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

iii  


 

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in thousands, except share and per share amounts)

 

 

2014

 

 

2013

Assets

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 98,864  

 

$

 21  

 

Accounts receivable, net of allowance for doubtful accounts:

 

 

 

 

 

 

 

 

Oil and natural gas

 

 

 256,214  

 

 

 223,790  

 

 

Joint operations and other

 

 

 338,362  

 

 

 247,945  

 

Derivative instruments

 

 

 41,859  

 

 

 590  

 

Deferred income taxes

 

 

 -    

 

 

 30,069  

 

Prepaid costs and other

 

 

 35,742  

 

 

 18,460  

 

 

  

Total current assets

 

 

 771,041  

 

 

 520,875  

Property and equipment:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

 

 13,048,470  

 

 

 11,215,373  

 

Accumulated depletion and depreciation

 

 

 (3,100,046) 

 

 

 (2,384,108) 

 

 

Total oil and natural gas properties, net

 

 

 9,948,424  

 

 

 8,831,265  

 

Other property and equipment, net

 

 

 117,244  

 

 

 114,783  

 

 

Total property and equipment, net

 

 

 10,065,668  

 

 

 8,946,048  

Deferred loan costs, net

 

 

 70,886  

 

 

 73,048  

Intangible asset - operating rights, net

 

 

 27,519  

 

 

 28,615  

Inventory

 

 

 15,829  

 

 

 19,682  

Noncurrent derivative instruments

 

 

 45,016  

 

 

 966  

Other assets

 

 

 42,136  

 

 

 1,930  

 

Total assets

 

$

 11,038,095  

 

$

 9,591,164  

Liabilities and Stockholders’ Equity

Current liabilities:

 

 

 

 

 

 

 

Accounts payable - trade

 

$

 33,499  

 

$

 13,936  

 

Bank overdrafts

 

 

 -    

 

 

 36,718  

 

Revenue payable

 

 

 190,793  

 

 

 177,617  

 

Accrued and prepaid drilling costs

 

 

 493,280  

 

 

 318,296  

 

Derivative instruments

 

 

 1,027  

 

 

 53,701  

 

Deferred income taxes

 

 

 2,504  

 

 

 -    

 

Other current liabilities

 

 

 170,239  

 

 

 156,600  

 

 

  

Total current liabilities

 

 

 891,342  

 

 

 756,868  

Long-term debt

 

 

 3,378,483  

 

 

 3,630,421  

Deferred income taxes

 

 

 1,521,582  

 

 

 1,334,653  

Noncurrent derivative instruments

 

 

 -    

 

 

 14,088  

Asset retirement obligations and other long-term liabilities

 

 

 102,910  

 

 

 97,185  

Commitments and contingencies (Note I)

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

Common stock, $0.001 par value; 300,000,000 authorized; 113,271,013 and

 

 

 

 

 

 

 

 

105,222,765 shares issued at September 30, 2014 and December 31, 2013, respectively

 

 

 113  

 

 

 105  

 

Additional paid-in capital

 

 

 3,010,524  

 

 

 2,027,162  

 

Retained earnings

 

 

 2,149,845  

 

 

 1,741,566  

 

Treasury stock, at cost; 175,378 and 127,305 shares at September 30, 2014 and

 

 

 

 

 

 

 

 

December 31, 2013, respectively

 

 

 (16,704) 

 

 

 (10,884) 

 

 

  

Total stockholders’ equity

 

 

 5,143,778  

 

 

 3,757,949  

 

Total liabilities and stockholders’ equity

 

$

 11,038,095  

 

$

 9,591,164  

 

 

 

 

 

 

 

 

 

 

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

  

1 


 

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in thousands, except per share amounts)

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

 575,611  

 

$

 553,068  

 

$

 1,696,240  

 

$

 1,412,887  

 

Natural gas sales

 

 

 124,652  

 

 

 99,852  

 

 

 369,684  

 

 

 274,946  

 

 

Total operating revenues

 

 

 700,263  

 

 

 652,920  

 

 

 2,065,924  

 

 

 1,687,833  

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas production

 

 

 140,725  

 

 

 120,231  

 

 

 402,593  

 

 

 328,295  

 

Exploration and abandonments

 

 

 16,982  

 

 

 10,992  

 

 

 70,645  

 

 

 37,797  

 

Depreciation, depletion and amortization

 

 

 256,765  

 

 

 200,625  

 

 

 715,602  

 

 

 557,775  

 

Accretion of discount on asset retirement obligations

 

 

 1,769  

 

 

 1,574  

 

 

 5,162  

 

 

 4,410  

 

Impairments of long-lived assets

 

 

 15,476  

 

 

 -    

 

 

 15,476  

 

 

 65,375  

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$13,465 and $9,923 for the three months ended September 30, 2014 and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 respectively, and $34,672 and $25,278 for the nine months ended

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014 and 2013, respectively)

 

 

 52,763  

 

 

 40,836  

 

 

 150,048  

 

 

 125,120  

 

(Gain) loss on derivatives not designated as hedges

 

 

 (326,229) 

 

 

 168,610  

 

 

 (125,907) 

 

 

 157,303  

 

 

Total operating costs and expenses

 

 

158,251

 

 

542,868

 

 

1,233,619

 

 

1,276,075

Income from operations

 

 

542,012

 

 

110,052

 

 

832,305

 

 

411,758

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

 (52,601) 

 

 

 (55,995) 

 

 

 (164,124) 

 

 

 (162,180) 

 

Loss on extinguishment of debt

 

 

 -    

 

 

 -    

 

 

 (4,316) 

 

 

 (28,616) 

 

Other, net

 

 

 2,155  

 

 

 (1,941) 

 

 

 (6,833) 

 

 

 (1,806) 

 

 

Total other expense

 

 

(50,446)

 

 

(57,936)

 

 

(175,273)

 

 

(192,602)

Income from continuing operations before income taxes

 

 

491,566

 

 

52,116

 

 

657,032

 

 

219,156

 

Income tax expense

 

 

 (186,363) 

 

 

 (21,695) 

 

 

 (248,753) 

 

 

 (86,023) 

Income from continuing operations

 

 

305,203

 

 

30,421

 

 

408,279

 

 

133,133

Income from discontinued operations, net of tax

 

 

 -    

 

 

 -    

 

 

 -    

 

 

 12,081  

Net income

 

$

 305,203  

 

$

 30,421  

 

$

 408,279  

 

$

 145,214  

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

2.70

 

$

0.29

 

$

3.74

 

$

1.27

 

Income from discontinued operations, net of tax

 

 

 -    

 

 

 -    

 

 

 -    

 

 

 0.12  

 

 

Net income

 

$

 2.70  

 

$

 0.29  

 

$

 3.74  

 

$

 1.39  

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

2.69

 

$

0.29

 

$

3.73

 

$

1.27

 

Income from discontinued operations, net of tax

 

 

 -    

 

 

 -    

 

 

 -    

 

 

 0.11  

 

 

Net income 

 

$

 2.69  

 

$

 0.29  

 

$

 3.73  

 

$

 1.38  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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, 2013

 

 105,223  

 

$

 105  

 

$

 2,027,162  

 

$

 1,741,566  

 

 127  

 

$

 (10,884) 

 

$

 3,757,949  

 

Net income

 

 -    

 

 

 -    

 

 

 -    

 

 

 408,279  

 

 -    

 

 

 -    

 

 

 408,279  

 

Issuance of common stock

 

 7,475  

 

 

 8  

 

 

 931,981  

 

 

 -    

 

 -    

 

 

 -    

 

 

 931,989  

 

Stock options exercised

 

 208  

 

 

 -    

 

 

 4,660  

 

 

 -    

 

 -    

 

 

 -    

 

 

 4,660  

 

Grants of restricted stock

 

 438  

 

 

 -    

 

 

 -    

 

 

 -    

 

 -    

 

 

 -    

 

 

 -    

 

Cancellation of restricted stock

 

 (73) 

 

 

 -    

 

 

 -    

 

 

 -    

 

 -    

 

 

 -    

 

 

 -    

 

Stock-based compensation

 

 -    

 

 

 -    

 

 

 34,672  

 

 

 -    

 

 -    

 

 

 -    

 

 

 34,672  

 

Excess tax benefits related to stock-based

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

compensation

 

 -    

 

 

 -    

 

 

 12,049  

 

 

 -    

 

 -    

 

 

 -    

 

 

 12,049  

 

Purchase of treasury stock

 

 -    

 

 

 -    

 

 

 -    

 

 

 -    

 

 48  

 

 

 (5,820) 

 

 

 (5,820) 

BALANCE AT SEPTEMBER 30, 2014

 

 113,271  

 

$

 113  

 

$

 3,010,524  

 

$

 2,149,845  

 

 175  

 

$

 (16,704) 

 

$

 5,143,778  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

3 


 

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

  

 

 

 

 

 

September 30,

(in thousands)

 

2014

 

2013

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income

 

$

 408,279  

 

$

 145,214  

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

 715,602  

 

 

 557,775  

 

 

Accretion of discount on asset retirement obligations

 

 

 5,162  

 

 

 4,410  

 

 

Impairments of long-lived assets

 

 

 15,476  

 

 

 65,375  

 

 

Exploration and abandonments, including dry holes

 

 

 56,626  

 

 

 13,159  

 

 

Non-cash stock-based compensation expense

 

 

 34,672  

 

 

 25,278  

 

 

Deferred income taxes

 

 

 219,502  

 

 

 75,808  

 

 

Loss on disposition of assets, net

 

 

 8,697  

 

 

 1,717  

 

 

(Gain) loss on derivatives not designated as hedges

 

 

 (125,907) 

 

 

 157,303  

 

 

Discontinued operations

 

 

 -    

 

 

 (12,250) 

 

 

Other non-cash items

 

 

 11,207  

 

 

 17,020  

 

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

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

 (75,963) 

 

 

 (113,226) 

 

 

 

Prepaid costs and other

 

 

 (19,317) 

 

 

 (1,866) 

 

 

 

Inventory

 

 

 3,058  

 

 

 434  

 

 

 

Accounts payable

 

 

 18,500  

 

 

 4,407  

 

 

 

Revenue payable

 

 

 13,176  

 

 

 44,983  

 

 

 

Other current liabilities

 

 

 (234) 

 

 

 (40,897) 

 

 

 

 

Net cash provided by operating activities

 

 

 1,288,536  

 

 

 944,644  

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Capital expenditures on oil and natural gas properties

 

 

 (1,754,835) 

 

 

 (1,426,349) 

 

Additions to property, equipment and other assets

 

 

 (25,267) 

 

 

 (21,311) 

 

Proceeds from the disposition of assets

 

 

 1,122  

 

 

 15,212  

 

Contribution to equity method investment

 

 

 (30,050) 

 

 

 -    

 

Funds held in escrow

 

 

 -    

 

 

 (1,964) 

 

Settlements paid on derivatives not designated as hedges

 

 

 (26,174) 

 

 

 (37,684) 

 

  

 

 

Net cash used in investing activities

 

 

 (1,835,204) 

 

 

 (1,472,096) 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Proceeds from issuance of debt

 

 

 1,578,000  

 

 

 3,283,875  

 

Payments of debt

 

 

 (1,828,000) 

 

 

 (2,798,400) 

 

Exercise of stock options

 

 

 4,660  

 

 

 2,304  

 

Excess tax benefit from stock-based compensation

 

 

 12,049  

 

 

 9,244  

 

Net proceeds from issuance of common stock

 

 

 931,989  

 

 

 -    

 

Payments for loan costs

 

 

 (10,649) 

 

 

 (14,075) 

 

Purchase of treasury stock

 

 

 (5,820) 

 

 

 (3,523) 

 

Bank overdrafts

 

 

 (36,718) 

 

 

 45,169  

 

  

 

 

Net cash provided by financing activities

 

 

 645,511  

 

 

 524,594  

 

  

 

 

Net increase (decrease) in cash and cash equivalents

 

 

 98,843  

 

 

 (2,858) 

Cash and cash equivalents at beginning of period

 

 

 21  

 

 

 2,880  

Cash and cash equivalents at end of period

 

$

 98,864  

 

$

 22  

 

 

 

 

 

 

 

 

 

 

 

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

 

 

4 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note A. 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 B. 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, the asset retirement obligations, fair value of derivative financial instruments, the 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, 2013 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, 2013.

 

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 $70.9 million and $73.0 million, net of accumulated amortization of $57.2 million and $48.7 million, at September 30, 2014 and December 31, 2013, respectively.

5 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

The following table reflects the future amortization expense of deferred loan costs at September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2014

  

$

 2,443  

2015

  

  

 9,973  

2016

  

  

 10,311  

2017

  

  

 10,670  

2018

  

  

 11,052  

2019

 

 

 8,342  

Thereafter

  

  

 18,095  

 

Total

  

$

70,886

 

 

  

 

 

 

Intangible assets.  The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at September 30, 2014 and December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

Gross intangible - operating rights

  

$

36,557

 

$

36,557

Accumulated amortization

  

  

(9,038)

 

 

(7,942)

 

Net intangible - operating rights

  

$

27,519

 

$

28,615

 

 

 

 

 

 

 

 

 

The following table reflects amortization expense for the three and nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

Three Months Ended

 

Nine Months Ended

 

 

  

September 30,

 

September 30,

(in thousands)

  

2014

 

2013

 

2014

 

2013

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Amortization expense

  

$

 365  

 

$

 365  

 

$

 1,096  

 

$

 1,096  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 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 $29.2 million at September 30, 2014 and is included in other assets in the Company’s consolidated balance sheet. The equity loss for the period since inception is approximately $0.9 million and is included in other expense in the Company’s consolidated statement of operations.

 

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.  

 

6 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

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 $6.1 million and $4.2 million for the three months ended September 30, 2014 and 2013, respectively, and $17.1 million and $13.5 million for the nine months ended September 30, 2014 and 2013, respectively.

 

Recent accounting pronouncements. In May 2014, the Financial Accounting Standards Board (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.

 

An entity is required to apply ASU 2014-09 for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. 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.

 

In April 2014, the FASB issued ASU No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (Topics 205 and 360),” that raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Under the revised standard, a discontinued operation is (i) a component of an entity or group of components that has been disposed of by sale, disposed of other than by sale or is classified as held for sale that represents a strategic shift that has or will have a major effect on an entity’s operations and financial results or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of the acquisition. This update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results.

 

An entity is required to apply ASU 2014-08 for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, though earlier adoption is permitted. An entity should provide the disclosures required by this amendment prospectively. The Company is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

 

Note C. 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 Q 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.

  

7 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

The following table reflects the Company’s net capitalized exploratory well activity during the nine months ended September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

  

Nine Months Ended

(in thousands)

 

  

September 30, 2014

 

 

 

 

 

 

 

 

Beginning capitalized exploratory well costs

 

 

 

 

$

144,504

 

Additions to exploratory well costs pending the determination of proved reserves

 

 

 

 

 

279,618

 

Reclassifications due to determination of proved reserves

 

 

 

 

 

(99,533)

 

Exploratory well costs charged to expense

 

 

 

 

 

(30,227)

Ending capitalized exploratory well costs

 

 

 

 

$

294,362

 

 

 

 

 

 

 

 

 

The following table provides an aging at September 30, 2014 and December 31, 2013 of capitalized exploratory well costs based on the date drilling was completed:

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(dollars in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

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

  

$

277,919

 

$

122,753

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

  

 

 16,443  

 

  

 21,751  

 

Total capitalized exploratory well costs

  

$

294,362

 

$

144,504

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

 

 

 

 

 

 

 

than one year

 

 

 10  

 

 

10

 

 

  

 

 

 

 

 

 

Southern Delaware Basin projects. At September 30, 2014, the Company had approximately $6.4 million of suspended well costs greater than one year recorded for one vertical well being evaluated in the Company’s Southern Delaware Basin project. The Company is assessing options to drill a horizontal lateral to continue evaluation of the target.

 

Projects operated by others. At September 30, 2014, the Company had approximately $6.3 million of suspended well costs greater than one year recorded for six wells that are operated by others and waiting on completion.

 

Other projects. At September 30, 2014, the Company had approximately $3.7 million of suspended well costs greater than one year recorded for three wells that have encountered technical difficulties that the Company plans to either recomplete or redrill.

8 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note D. Asset retirement obligations

 

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company's asset retirement obligation activity during the nine months ended September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

(in thousands)

 

 

September 30, 2014

 

 

 

 

 

 

 

 

Asset retirement obligations, beginning of period

 

 

 

 

$

 101,593  

 

Liabilities incurred from new wells

  

 

 

 

  

 3,122  

 

Liabilities assumed in acquisitions

  

 

 

 

  

 1,337  

 

Accretion expense

  

 

 

 

  

 5,162  

 

Liabilities settled upon plugging and abandoning wells

  

 

 

 

  

 (4,049) 

 

Revision of estimates

  

 

 

 

  

 4,753  

Asset retirement obligations, end of period

 

 

 

 

$

 111,918  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Note E.  Stock incentive plan

 

The Company’s 2006 Stock Incentive Plan, as amended and restated, 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 nine months ended September 30, 2014 is presented below:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted

 

Stock

 

Performance

 

 

 

 

Stock

 

Options

 

Units

 

Outstanding at December 31, 2013

 

  

 1,216,449  

 

 

255,537

 

 

110,889

 

 

Awards granted (a)

 

  

 438,380  

 

 

 -    

 

 

 139,425  

 

 

Options exercised

 

  

 -    

 

 

(207,824)

 

 

 -    

 

 

Awards cancelled / forfeited

 

  

(72,956)

 

 

 -    

 

 

 -    

 

 

Lapse of restrictions

 

 

(273,745)

 

 

 -    

 

 

 -    

 

Outstanding at September 30, 2014

 

 1,308,128  

 

 47,713  

 

 250,314  

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Weighted average grant date fair value per share

 

$

 129.69  

 

$

 -    

 

$

 139.54  

 

 

 

 

  

 

 

 

 

 

 

 

9 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

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 September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2014

 

$

12,653

2015

 

  

40,470

2016

 

  

25,115

2017

 

  

6,934

2018

 

  

794

Thereafter

 

 

3

 

Total

  

$

85,969

 

 

 

 

 

 

Note F. Disclosures about fair value of financial instruments

 

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.

10 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

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 September 30, 2014 and December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014

 

December 31, 2013

 

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

(in thousands)

 

Value

 

Value

 

Value

 

Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

 86,875  

 

$

 86,875  

 

$

 1,556  

 

$

 1,556  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

 1,027  

 

$

 1,027  

 

$

 67,789  

 

$

 67,789  

 

 

Credit facility

 

$

 -    

 

$

 -    

 

$

 250,000  

 

$

 250,770  

 

 

7.0% senior notes due 2021

 

$

 600,000  

 

$

 640,500  

 

$

 600,000  

 

$

 660,000  

 

 

6.5% senior notes due 2022

 

$

 600,000  

 

$

 637,500  

 

$

 600,000  

 

$

 649,500  

 

 

5.5% senior notes due 2022

 

$

 600,000  

 

$

 618,000  

 

$

 600,000  

 

$

 619,500  

 

 

5.5% senior notes due 2023

 

$

 1,578,483  

 

$

 1,641,622  

 

$

 1,580,421  

 

$

 1,627,834  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

  

11 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

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 table summarizes (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 September 30, 2014 and December 31, 2013. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 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

 

$

 -    

 

$

 56,037  

 

$

 -    

 

$

 56,037  

 

$

 (14,178) 

 

$

 41,859  

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

  

 47,200  

 

  

 -    

 

  

 47,200  

 

  

 (2,184) 

 

  

 45,016  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

 

 (15,205) 

 

 

 -    

 

 

 (15,205) 

 

 

 14,178  

 

 

 (1,027) 

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

  

 (2,184) 

 

  

 -    

 

  

 (2,184) 

 

  

 2,184  

 

  

 -    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

 -    

 

$

 85,848  

 

$

 -    

 

$

 85,848  

 

$

 -    

 

$

 85,848  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

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

 

$

 -    

 

$

 12,819  

 

$

 -    

 

$

 12,819  

 

$

 (12,229) 

 

$

 590  

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

  

 5,300  

 

  

 -    

 

  

 5,300  

 

  

 (4,334) 

 

  

 966  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

  

 (65,930) 

 

  

 -    

 

  

 (65,930) 

 

  

 12,229  

 

  

 (53,701) 

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

 -    

 

  

 (18,422) 

 

  

 -    

 

  

 (18,422) 

 

  

 4,334  

 

  

 (14,088) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

 -    

 

$

 (66,233) 

 

$

 -    

 

$

 (66,233) 

 

$

 -    

 

$

 (66,233) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Concentrations of credit risk. As of September 30, 2014, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable – trade 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 G for additional information regarding the Company's derivative activities.

13 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

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.

 

The Company calculates the estimated fair values using a discounted future cash flow model. Assumptions associated with the calculation of discounted future cash flows include commodity prices based on New York Mercantile Exchange (“NYMEX”)  futures price strips (Level 1), as well as Level 3 assumptions including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes and (v) estimated proved reserves.

 

As a result of management’s assessments, the Company recognized impairment charges to reduce the carrying values to their fair values. The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

 

 

 

 

Carrying

 

 

Fair Value

 

 

Impairment

(in thousands)

 

 

 Amount 

 

 

(Level 3)

 

 

Expense

 

 

 

 

 

 

 

 

 

 

September 2014

 

$

 26,790  

 

$

 11,314  

 

$

 15,476  

June 2013

 

$

 84,140  

 

$

 18,765  

 

$

 65,375  

 

 

 

 

 

 

 

 

 

 

 

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

14 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note G. 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 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 nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

September 30,

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

 316,559  

 

$

 (169,049) 

 

$

 128,684  

 

$

 (172,698) 

 

 

Natural gas derivatives

 

 

 9,670  

 

 

 439  

 

 

 (2,777) 

 

 

 15,395  

 

 

 

Total

 

$

 326,229  

 

$

 (168,610) 

 

$

 125,907  

 

$

 (157,303) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents the Company's cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2014 and 2013:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

September 30,

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

 14,271  

 

$

 (49,864) 

 

$

 (20,067) 

 

$

 (42,528) 

 

 

Natural gas derivatives

 

  

 446  

 

  

 4,589  

 

  

 (6,107) 

 

  

 4,844  

 

 

 

Total

 

$

 14,717  

 

$

 (45,275) 

 

$

 (26,174) 

 

$

 (37,684) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

15 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Commodity derivative contracts at September 30, 2014. The following table sets forth the Company’s outstanding derivative contracts at September 30, 2014. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 2014 are expected to settle by June 30, 2017.

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

Oil Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2014:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

 4,633,000  

 

 4,633,000  

 

 

Price per Bbl

 

 

 

 

 

 

$

92.49

$

92.49

 

2015:

  

 

  

 

  

 

  

 

  

 

 

 

Volume (Bbl)

 

 4,240,000  

 

 3,919,000  

 

 3,654,000  

 

 3,449,000  

 

 15,262,000  

 

 

Price per Bbl

$

88.32

$

87.50

$

87.57

$

87.42

$

87.73

 

2016:

  

 

  

 

  

 

  

 

  

 

 

 

Volume (Bbl)

  

 3,218,000  

  

 3,068,000  

  

 2,958,000  

  

 105,000  

  

 9,349,000  

 

 

Price per Bbl

$

90.43

$

90.90

$

90.46

$

88.28

$

90.57

 

2017:

  

 

  

 

  

 

  

 

  

 

 

 

Volume (Bbl)

  

 84,000  

  

 84,000  

  

 -  

  

 -  

  

 168,000  

 

 

Price per Bbl

$

87.00

$

87.00

$

 -    

$

 -    

$

87.00

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2014:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

  

 

 

 

 

 

 

 3,956,000  

 

 3,956,000  

 

 

Price per Bbl

  

 

 

 

 

 

$

(1.07)

$

(1.07)

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 1,620,000  

 

 1,638,000  

 

 1,932,000  

 

 1,932,000  

 

 7,122,000  

 

 

Price per Bbl

$

(3.30)

$

(3.30)

$

(3.50)

$

(3.50)

$

(3.41)

Natural Gas Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2014:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

 2,053,000  

 

 2,053,000  

 

 

Price per MMBtu

 

 

 

 

 

 

$

4.24

$

4.24

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 5,850,000  

 

 5,915,000  

 

 5,980,000  

 

 5,980,000  

 

 23,725,000  

 

 

Price per MMBtu

$

4.16

$

4.16

$

4.16

$

4.16

$

4.16

Natural Gas Collars: (d)

 

 

 

 

 

 

 

 

 

 

 

2014:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

 5,520,000  

 

 5,520,000  

 

 

Ceiling price per MMBtu

 

 

 

 

 

 

$

4.40

$

4.40

 

 

Floor price per MMBtu

 

 

 

 

 

 

$

3.85

$

3.85

Natural Gas Basis Swaps: (e)

 

 

 

 

 

 

 

 

 

 

 

2014:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

 2,053,000  

 

 2,053,000  

 

 

Price per MMBtu

 

 

 

 

 

 

$

(0.11)

$

(0.11)

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 1,350,000  

 

 1,365,000  

 

 1,380,000  

 

 1,380,000  

 

 5,475,000  

 

 

Price per MMBtu

$

(0.13)

$

(0.13)

$

(0.13)

$

(0.13)

$

(0.13)

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The index prices for the oil price swaps are based on the 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 index prices for the natural gas collars are based on the El Paso Permian delivery point.

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

16 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

 

Derivative counterparties.  The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

 

Note H. Debt 

 

The Company’s debt consisted of the following at September 30, 2014 and December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

Credit facility

 

$

 -    

 

$

 250,000  

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

 

  

 28,483  

 

  

 30,421  

 

Less: current portion

 

  

 -    

 

  

 -    

 

 

Total long-term debt

 

$

 3,378,483  

 

$

 3,630,421  

 

 

 

 

 

 

 

 

 

 

Credit facility. The Company’s credit facility, as amended and restated, has a maturity date of May 9, 2019. As of September 30, 2014, the Company’s borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2015, and commitments from the Company’s bank group total $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 O.

 

At September 30, 2014, 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 September 30, 2014 were as follows:

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Remaining 2014

 

$

 

 -    

2015

 

 

 

 -    

2016

 

 

 

 -    

2017

 

 

 

 -    

2018

 

 

 

 -    

2019

 

 

 

 -    

Thereafter

 

 

 

 3,350,000  

 

Total

$

 

 3,350,000  

 

 

 

 

 

 

17 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Interest expense.  The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

 

September 30,

 

September 30,

(in thousands)

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash payments for interest

  

$

 42,417  

 

$

 43,868  

  

$

 152,217  

 

$

 145,980  

Amortization of original issue discount (premium)

 

 

 (654) 

 

 

 (620) 

  

 

 (1,936) 

 

 

 (619) 

Amortization of deferred loan origination costs

 

 

 2,423  

 

 

 3,311  

  

 

 8,495  

 

 

 9,844  

Net changes in accruals

 

 

 9,312  

 

 

 9,436  

  

 

 6,245  

 

 

 6,975  

 

Interest costs incurred

 

 

 53,498  

 

 

 55,995  

  

 

 165,021  

 

 

 162,180  

Less: capitalized interest

 

 

 (897) 

 

 

 -    

 

 

 (897) 

 

 

 -    

 

Total interest expense

 

$

 52,601  

 

$

 55,995  

 

$

 164,124  

 

$

 162,180  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Note I. 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 $7.0 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 September 30, 2014 and December 31, 2013, the Company had $12.9 million and $12.2 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. 

18 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Contractual drilling commitments.  The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Payments Due By Period

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

  

Less than

 

  

1-3

 

  

3-5

 

  

More than

 (in thousands)

 

 

 Total 

 

 

1 year

 

 

years

 

 

years

 

 

5 years

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contractual drilling commitments

 

$

 32,126  

 

$

 29,478  

 

$

 2,648  

 

$

 -    

 

$

 -    

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 September 30, 2014 and 2013 were approximately $1.9 million and $1.5 million, respectively, and approximately $5.3 million and $4.2 million for the nine months ended September 30, 2014 and 2013, respectively.

 

Future minimum lease commitments under non-cancellable operating leases at September 30, 2014 were as follows:

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2014

 

$

1,828

2015

 

 

6,387

2016

 

 

4,969

2017

 

 

4,984

2018

 

 

4,279

2019

 

 

3,980

Thereafter

 

 

8,660

 

Total

$

35,087

 

 

 

 

 

 

Note J. Income taxes

 

The effective income tax rates were 37.9 percent and 41.6 percent for the three months ended September 30, 2014 and 2013, respectively, and 37.9 percent and 39.3 percent for the nine months ended September 30, 2014 and 2013, respectively.

 

During the three months ended September 30, 2014 and 2013, the Company recorded expense of $0.7 million and $1.3 million, respectively, associated with revisions of estimates based on filing its 2013 and 2012 tax returns, respectively. During the three and nine months ended September 30, 2014 and the nine months ended September 30, 2013, the revisions did not result in a significant change to the Company’s effective rates. During the three months ended September 30, 2013, the revision increased the Company’s effective rate by 2.4 percent from 39.2 percent.

 

During the fourth quarter of 2013, the Company revised its estimated blended effective state tax rate to consider (a) New Mexico legislation passed that phases in a tax rate reduction from 7.6 percent to 5.9 percent in 2018 and (b) the apportionment factor for states in which the Company operates. Total income tax expense for the three and nine months ended September 30, 2014 and 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.  

19 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note K. 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

 

Nine Months Ended

 

 

 

 

 

 

September 30,

 

September 30,

(in thousands)

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

4,955

 

$

2,010

 

$

11,010

 

$

4,694

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

48

 

$

12

 

$

205

 

$

33

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts paid under consulting agreement with Steven L. Beal (c)

 

$

 -    

 

$

745

 

$

 -    

 

$

865

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)   Royalties paid on certain properties to a partnership of which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

 

(b)   Payments made to a director and certain officers who directly own overriding royalty interests in properties owned by the Company.

 

(c)   On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

  

 

 

 

Note L. Discontinued operations

 

In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.1 million. As a result of post-closing adjustments during the nine months ended September 30, 2013, the Company made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million, before income tax expense of approximately $7.5 million. The Company recognized income from discontinued operations, net of tax of $12.1 million for the nine months ended September 30, 2013.

20 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note M. Net income per share

 

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

 

The following tables reconcile the Company’s income from continuing operations, income from discontinued operations and income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the three and nine months ended September 30, 2014 and 2013, respectively, under the two-class method:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

Nine Months Ended

 

 

 

 

 

September 30, 2014

 

 

September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing

 

Discontinued

 

 

 

 

Continuing

 

Discontinued

 

 

 

(in thousands, except per share amounts)

 

Operations

 

Operations

 

Total

 

Operations

 

Operations

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income as reported

 

$

305,203

 

$

 -    

 

$

305,203

 

$

408,279

 

$

 -    

 

$

408,279

Participating basic earnings

 

 

(3,557)

 

 

 -    

 

 

(3,557)

 

 

(4,687)

 

 

 -    

 

 

(4,687)

 

Basic income attributable to common

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

stockholders

 

 

301,646

 

 

 -    

 

 

301,646

 

 

403,592

 

 

 -    

 

 

403,592

Reallocation of participating earnings

 

 

10

 

 

 -    

 

 

 10  

 

 

15

 

 

 -    

 

 

 15  

 

Diluted income attributable to common

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

stockholders

$

301,656

 

$

 -    

 

$

301,656

 

$

403,607

 

$

 -    

 

$

403,607

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

 2.70  

 

$

 -    

 

$

 2.70  

 

$

 3.74  

 

$

 -    

 

$

 3.74  

 

Diluted

 

$

 2.69  

 

$

 -    

 

$

 2.69  

 

$

 3.73  

 

$

 -    

 

$

 3.73  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

21 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

Nine Months Ended

 

 

 

 

 

September 30, 2013

 

 

September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing

 

Discontinued

 

 

 

 

Continuing

 

Discontinued

 

 

 

(in thousands, except per share amounts)

 

Operations

 

Operations

 

Total

 

Operations

 

Operations

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income as reported

 

$

30,421

 

$

 -  

 

$

30,421

 

$

133,133

 

$

 12,081  

 

$

145,214

Participating basic earnings

 

 

(357)

 

 

 -  

 

 

(357)

 

 

(1,421)

 

 

(129)

 

 

(1,550)

 

Basic income attributable to common

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

stockholders

 

 

30,064

 

 

 -  

 

 

30,064

 

 

131,712

 

 

11,952

 

 

143,664

Reallocation of participating earnings

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 2  

 

 

 -  

 

 

 2  

 

Diluted income attributable to common

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

stockholders

 

$

30,064

 

$

 -  

 

$

30,064

 

$

131,714

 

$

11,952

 

$

143,666

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

 0.29  

 

$

 -  

 

$

 0.29  

 

$

 1.27  

 

$

 0.12  

 

$

 1.39  

 

Diluted

 

$

 0.29  

 

$

 -  

 

$

 0.29  

 

$

 1.27  

 

$

 0.11  

 

$

 1.38  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

  

 

 

 

  

 

 

 

 

Basic

  

 111,680  

 

 103,801  

 

 107,816  

 

 103,709  

 

 

Dilutive common stock options

  

 75  

 

 157  

 

 102  

 

 173  

 

 

Dilutive performance units

  

 244  

 

 -  

 

 230  

 

 -  

 

Diluted

  

 111,999  

 

 103,958  

  

 108,148  

 

 103,882  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

22 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

The following table is a summary of the restricted stock and performance units, which were not included in the computation of diluted income per share, as inclusion of these items would be antidilutive:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

Number of antidilutive common shares:

  

 

 

 

  

 

 

 

 

Antidilutive restricted stock

  

 18  

 

 2  

 

 119  

 

 7  

 

Antidilutive performance units

  

 -  

 

 111  

 

 -  

 

 111  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Note N. Stockholders’ equity

 

Public common stock offering. In May 2014, the Company issued, including the over-allotment option, in a secondary public offering 7.475 million shares of its common stock at $129.00 per share and received net proceeds of approximately $932.0 million. The Company used a portion of the net proceeds from this offering to repay all outstanding borrowings under its credit facility.

 

Note O. 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 H 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 September 30, 2014 and December 31, 2013, condensed consolidating statements of operations for the three and nine months ended September 30, 2014 and 2013 and condensed consolidating statements of cash flows for the nine months ended September 30, 2014 and 2013, 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.

23 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Condensed Consolidating Balance Sheet

September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

  

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

  

 

 

  

 

 

Accounts receivable - related parties

  

$

 6,557,085  

 

$

 1,208,417  

 

$

 (7,765,502) 

 

$

 -    

Other current assets

  

 

 50,885  

 

 

 720,156  

 

 

 -    

 

 

 771,041  

Oil and natural gas properties, net

  

 

 -    

 

 

 9,948,424  

 

 

 -    

 

 

 9,948,424  

Property and equipment, net

  

 

 -    

 

 

 117,244  

 

 

 -    

 

 

 117,244  

Investment in subsidiaries

  

 

 4,598,055  

 

 

 -    

 

 

 (4,598,055) 

 

 

 -    

Other long-term assets

  

 

 115,901  

 

 

 85,485  

 

 

 -    

 

 

 201,386  

 

Total assets

  

$

 11,321,926  

  

$

 12,079,726  

  

$

 (12,363,557) 

  

$

 11,038,095  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

  

 

 

  

 

 

Accounts payable - related parties

  

$

 1,208,417  

 

$

 6,557,085  

 

$

 (7,765,502) 

 

$

 -    

Other current liabilities

  

 

 69,666  

 

 

 821,676  

 

 

 -    

 

 

 891,342  

Long-term debt

  

 

 3,378,483  

 

 

 -    

 

 

 -    

 

 

 3,378,483  

Other long-term liabilities

  

 

 1,521,582  

 

 

 102,910  

 

 

 -    

 

 

 1,624,492  

Equity

  

 

 5,143,778  

 

 

 4,598,055  

 

 

 (4,598,055) 

 

 

 5,143,778  

 

Total liabilities and equity

  

$

 11,321,926  

  

$

 12,079,726  

  

$

 (12,363,557) 

  

$

 11,038,095  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Balance Sheet

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

 

 

 

  

 

 

Accounts receivable - related parties

  

$

 6,115,554  

 

$

 1,261,844  

 

$

 (7,377,398) 

 

$

 -    

Other current assets

  

 

 39,108  

 

 

 481,767  

 

 

 -    

 

 

 520,875  

Oil and natural gas properties, net

  

 

 -    

 

 

 8,831,265  

 

 

 -    

 

 

 8,831,265  

Property and equipment, net

  

 

 -    

 

 

 114,783  

 

 

 -    

 

 

 114,783  

Investment in subsidiaries

  

 

 3,896,741  

 

 

 -    

 

 

 (3,896,741) 

 

 

 -    

Other long-term assets

  

 

 74,013  

 

 

 50,228  

 

 

 -    

 

 

 124,241  

 

Total assets

  

$

 10,125,416  

  

$

 10,739,887  

 

$

 (11,274,139) 

  

$

 9,591,164  

 

 

  

 

 

  

 

 

 

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

 

 

 

  

 

 

Accounts payable - related parties

  

$

 1,261,844  

 

$

 6,115,554  

 

$

 (7,377,398) 

 

$

 -    

Other current liabilities

  

 

 126,461  

 

 

 630,407  

 

 

 -    

 

 

 756,868  

Long-term debt

  

 

 3,630,421  

 

 

 -    

 

 

 -    

 

 

 3,630,421  

Other long-term liabilities

  

 

 1,348,741  

 

 

 97,185  

 

 

 -    

 

 

 1,445,926  

Equity

  

 

 3,757,949  

 

 

 3,896,741  

 

 

 (3,896,741) 

 

 

 3,757,949  

 

Total liabilities and equity

  

$

 10,125,416  

  

$

 10,739,887  

 

$

 (11,274,139) 

  

$

 9,591,164  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

24 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

 -    

 

$

 700,263  

 

$

 -    

 

$

 700,263  

Total operating costs and expenses

  

 

 325,637  

 

 

 (483,888) 

 

 

 -    

 

 

 (158,251) 

 

Income from operations

  

 

 325,637  

 

 

 216,375  

 

 

 -    

 

 

 542,012  

Interest expense

  

 

 (52,601) 

 

 

 -    

 

 

 -    

 

 

 (52,601) 

Other, net

  

 

 218,530  

 

 

 2,155  

 

 

 (218,530) 

 

 

 2,155  

 

Income before income taxes

  

 

 491,566  

 

 

 218,530  

 

 

 (218,530) 

 

 

 491,566  

Income tax expense

  

 

 (186,363) 

 

 

 -    

 

 

 -    

 

 

 (186,363) 

 

Net income

  

$

 305,203  

 

$

 218,530  

 

$

 (218,530) 

 

$

 305,203  

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

 -    

 

$

 652,920  

 

$

 -    

 

$

 652,920  

Total operating costs and expenses

  

 

 (169,935) 

 

 

 (372,933) 

 

 

 -    

 

 

 (542,868) 

 

Income (loss) from operations

  

 

 (169,935) 

 

 

 279,987  

 

 

 -    

 

 

 110,052  

Interest expense

  

 

 (55,995) 

 

 

 -    

 

 

 -    

 

 

 (55,995) 

Other, net

  

 

 278,046  

 

 

 (1,996) 

 

 

 (277,991) 

 

 

 (1,941) 

 

Income before income taxes

  

 

 52,116  

 

 

 277,991  

 

 

 (277,991) 

 

 

 52,116  

Income tax expense

  

 

 (21,695) 

 

 

 -    

 

 

 -    

 

 

 (21,695) 

 

Net income

  

$

 30,421  

 

$

 277,991  

 

$

 (277,991) 

 

$

 30,421  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

25 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

 -    

 

$

 2,065,924  

 

$

 -    

 

$

 2,065,924  

Total operating costs and expenses

  

 

 124,158  

 

 

 (1,357,777) 

 

 

 -    

 

 

 (1,233,619) 

 

Income from operations

  

 

 124,158  

 

 

 708,147  

 

 

 -    

 

 

 832,305  

Interest expense

  

 

 (164,124) 

 

 

 -    

 

 

 -    

 

 

 (164,124) 

Loss on extinguishment of debt

 

 

 (4,316) 

 

 

 -    

 

 

 -    

 

 

 (4,316) 

Other, net

  

 

 701,314  

 

 

 (6,833) 

 

 

 (701,314) 

 

 

 (6,833) 

 

Income before income taxes

  

 

 657,032  

 

 

 701,314  

 

 

 (701,314) 

 

 

 657,032  

Income tax expense

  

 

 (248,753) 

 

 

 -    

 

 

 -    

 

 

 (248,753) 

 

Net income

  

$

 408,279  

 

$

 701,314  

 

$

 (701,314) 

 

$

 408,279  

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

 -    

 

$

 1,687,833  

 

$

 -    

 

$

 1,687,833  

Total operating costs and expenses

  

 

 (159,017) 

 

 

 (1,117,058) 

 

 

 -    

 

 

 (1,276,075) 

 

Income (loss) from continuing operations

  

 

 (159,017) 

 

 

 570,775  

 

 

 -    

 

 

 411,758  

Interest expense

  

 

 (162,180) 

 

 

 -    

 

 

 -    

 

 

 (162,180) 

Loss on extinguishment of debt

  

 

 (28,616) 

 

 

 -    

 

 

 -    

 

 

 (28,616) 

Other, net

  

 

 588,568  

 

 

 (1,863) 

 

 

 (588,511) 

 

 

 (1,806) 

 

Income from continuing operations before income taxes

  

 

 238,755  

 

 

 568,912  

 

 

 (588,511) 

 

 

 219,156  

Income tax expense

  

 

 (86,023) 

 

 

 -    

 

 

 -    

 

 

 (86,023) 

 

Income from continuing operations

  

 

 152,732  

 

 

 568,912  

 

 

 (588,511) 

 

 

 133,133  

Income (loss) from discontinued operations, net of tax

  

 

 (7,518) 

 

 

 19,599  

 

 

 -    

 

 

 12,081  

 

Net income

  

$

 145,214  

 

$

 588,511  

 

$

 (588,511) 

 

$

 145,214  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

26 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

  

$

 (656,055) 

 

$

 1,944,591  

 

$

 -    

 

$

 1,288,536  

Net cash flows used in investing activities

 

 

 (26,174) 

 

 

 (1,809,030) 

 

 

 -    

 

 

 (1,835,204) 

Net cash flows provided by (used in) financing activities

  

 

 682,229  

 

 

 (36,718) 

 

 

 -    

 

 

 645,511  

 

Net increase in cash and cash equivalents

  

 

 -    

 

 

 98,843  

 

 

 -    

 

 

 98,843  

 

Cash and cash equivalents at beginning of period

  

 

 -    

 

 

 21  

 

 

 -    

 

 

 21  

 

Cash and cash equivalents at end of period

  

$

 -    

 

$

 98,864  

 

$

 -    

 

$

 98,864  

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 





Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

 

$

 (441,741) 

 

$

 1,386,385  

 

$

 -    

  

$

 944,644  

Net cash flows used in investing activities

  

 

 (37,684) 

 

 

 (1,434,412) 

 

 

 -    

  

 

 (1,472,096) 

Net cash flows provided by financing activities

  

 

 479,425  

 

 

 45,169  

 

 

 -    

  

 

 524,594  

 

Net decrease in cash and cash equivalents

  

 

 -    

 

 

 (2,858) 

 

 

 -    

 

 

 (2,858) 

 

Cash and cash equivalents at beginning of period

  

 

 -    

 

 

 2,880  

 

 

 -    

 

 

 2,880  

 

Cash and cash equivalents at end of period

  

$

 -    

 

$

 22  

 

$

 -    

 

$

 22  

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

27 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note P. Subsequent events

 

New commodity derivative contracts.  After September 30, 2014, the Company entered into the following oil basis swaps to hedge additional amounts of the Company’s estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Basis Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 1,395,000  

 

 1,288,500  

 

 782,000  

 

 552,000  

 

 4,017,500  

 

 

Price per Bbl

$

 (4.25) 

$

 (4.29) 

$

 (4.34) 

$

 (4.35) 

$

 (4.29) 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

28 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2014

Unaudited

 

Note Q. Supplementary information

 

Capitalized costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(in thousands)

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Oil and natural gas properties:

 

 

 

 

 

 

 

Proved

 

$

11,863,067

 

$

10,182,953

 

Unproved

 

 

1,185,403

 

 

1,032,420

 

Less: accumulated depletion

 

 

(3,100,046)

 

 

(2,384,108)

 

 

Net capitalized costs for oil and natural gas properties

 

$

9,948,424

 

$

8,831,265

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs incurred for oil and natural gas producing activities  (a)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

  

 

 

 

 

 

 

Proved

  

$

 37,732  

 

$

 -    

 

$

 60,359  

 

$

2,376

 

Unproved

  

 

 71,915  

 

 

13,991

 

 

 107,985  

 

 

58,832

Exploration

  

 

 469,290  

 

 

229,082

 

 

 1,136,211  

 

 

779,026

Development

  

 

 204,938  

 

 

197,696

 

 

 609,780  

 

 

593,006

 

Total costs incurred for oil and natural gas properties

  

$

 783,875  

 

$

440,769

  

$

 1,914,335  

 

$

1,433,240

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

 

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploration costs

 

$

 730  

 

$

 535  

 

$

 1,850  

 

$

 2,089  

 

Development costs

  

 

 4,721  

 

 

 1,801  

 

 

 6,025  

 

 

 9,163  

 

 

Total asset retirement obligations

  

$

 5,451  

 

$

 2,336  

  

$

 7,875  

 

$

 11,252  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

29 


     

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 both on a vertical and horizontal basis, (ii) Delaware Basin, where we primarily target the Bone Spring formation (which includes the Avalon Shale and the Bone Spring sands) and the Wolfcamp shale, all primarily on a horizontal basis, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons, primarily on a vertical basis and the Wolfcamp shale on a horizontal basis.  Oil comprised 61.1 percent of our 502.9 MMBoe of estimated proved reserves at December 31, 2013 and 63.8 percent of our 29.4 MMBoe of production for the nine months ended September 30, 2014. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 91.1 percent of our proved developed producing PV-10 and 80.3 percent of our approximately 6,530 gross wells at December 31, 2013. By controlling operations, we are able to more effectively manage the cost, timing and drilling and stimulation methods used in the exploration and development of our properties.

 

Financial and Operating Performance

 

Our financial and operating performance for the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013, included the following highlights:

 

·         Net income was $408.3 million ($3.73 per diluted share) for the first nine months of 2014, as compared to net income of $145.2 million ($1.38 per diluted share) during the nine months ended September 30, 2013. The increase in net income was primarily due to:

 

       $378.1 million increase in oil and natural gas revenues as a result of a 19 percent increase in production and a 3 percent increase in commodity price realizations per Boe (excluding the effects of derivative activities);

 

       $125.9 million gain on derivatives not designated as hedges for the nine months ended September 30, 2014, as compared to a $157.3 million loss on derivatives not designated as hedges during the nine months ended September 30, 2013;

 

       $65.4 million non-cash impairment charge due primarily to downward adjustments to our economically recoverable proved reserves due to (i) reduced well performance and (ii) decreases in our estimated realized natural gas prices, primarily on non-core natural gas assets in our New Mexico Shelf area during the nine months ended September 30, 2013, as compared to a $15.5 million non-cash impairment charge due primarily to downward adjustments to our economically recoverable proved reserves due to decreases in our estimated realized oil and natural gas prices, on non-core assets in our Delaware Basin area during the nine months ended September 30, 2014; and

 

       $28.6 million loss on extinguishment of debt during the nine months ended September 30, 2013 related to the tender offer and redemption of our 8.625% senior notes due 2017 (the “8.625% Notes”) compared to $4.3 million loss on extinguishment of debt during the nine months ended September 30, 2014 related to our amended and restated credit facility;

 

 

 

30 


     

partially offset by:

 

       $157.8 million increase in depreciation, depletion and amortization (“DD&A”) expense, primarily due to increased production associated with new wells that were successfully drilled and completed in 2013 and 2014

 

       $74.3 million increase in oil and natural gas production costs due in part to increased production related to our wells successfully drilled and completed in 2013 and 2014;

 

       $32.8 million increase in exploration and abandonment expense due primarily to unsuccessful wells and leasehold abandonments;

 

       $24.9 million increase in general and administrative expense due to an increase in the number of employees and related personnel expenses to manage our increased activities related to our increased drilling and exploration activities; and

 

       $12.1 million income from discontinued operations, net of tax in 2013 related to the post-closing adjustments to our sale of certain non-core assets in the fourth quarter of 2012.

 

·         Average daily sales volumes increased by 19 percent from 90,514 Boe per day during the first nine months of 2013 to 107,682 Boe per day during the first nine months of 2014. The increase is primarily attributable to our successful drilling efforts during 2013 and 2014.

 

·         Net cash provided by operating activities increased by approximately $343.9 million to $1,288.5 million for the first nine months of 2014, as compared to $944.6 million in the first nine months of 2013, primarily due to (i) increased oil and natural gas revenues and (ii) positive variances in working capital changes, offset by cash increases in related oil and natural gas production costs and general and administrative expense.

 

·         Long-term debt decreased by approximately $251.9 million during the first nine months of 2014, primarily due to utilizing a portion of the net proceeds from our equity offering to repay all outstanding borrowings under our credit facility.

 

·         At September 30, 2014, we had $98.9 million of cash and cash equivalents and $2.5 billion available under our credit facility.

 

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, (ii) natural gas and natural gas liquids 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 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 supply through export quotas;

 

·         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;

 

31 


     

·         the proximity, capacity, cost and availability of pipelines and other transportation facilities;

 

·         the quality of the oil we produce;

 

·         the overall global demand for oil; 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 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 Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at September 30, 2014.

 

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 higher during the comparable year-to-date periods of 2014 measured against 2013; however, the average oil prices during the comparable quarter-to-date periods of 2014 measured against 2013 were moderately less. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and nine months ended September 30, 2014 and 2013, as well as the high and low NYMEX prices for the same periods:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

  

 

 

 

September 30,

 

September 30,

 

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl)

  

$

 97.31  

 

$

 105.94  

  

$

 99.65  

 

$

 98.21  

 

Natural gas (MMBtu)

  

$

 3.95  

 

$

 3.55  

  

$

 4.41  

 

$

 3.69  

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

High and Low NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

  

$

 105.34  

 

$

 110.53  

  

$

 107.26  

 

$

 110.53  

 

 

Low

  

$

 91.16  

 

$

 97.99  

  

$

 91.16  

 

$

 86.68  

 

Natural gas (MMBtu):

  

 

 

 

 

 

  

 

 

 

 

 

 

 

High

  

$

 4.46  

 

$

 3.81  

  

$

 6.15  

 

$

 4.41  

 

 

Low

  

$

 3.75  

 

$

 3.23  

  

$

 3.75  

 

$

 3.11  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

 

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $91.01 and $77.19 per Bbl and $4.13 and $3.56 per MMBtu, respectively, during the period from September 30, 2014 to November 4, 2014. The significant drop in oil prices has been attributed to higher supplies and weaker demands. At November 4, 2014, the NYMEX oil price and NYMEX natural gas price were $77.19 per Bbl and $4.13 per MMBtu, respectively.

 

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 September 30, 2014 and 2013, the basis differential between WTI-Midland and WTI-Cushing was a price reduction of $9.96 per Bbl and $0.27 per Bbl, respectively, which is the primary reason for the lower realized oil price as a percentage of the NYMEX price in 2014 compared to the same period of 2013. For the nine months ended September 30, 2014 and 2013, the basis differential between WTI-Midland and WTI-Cushing was a price reduction of $7.28 per Bbl and $2.74 per Bbl, respectively, which is the primary reason for the lower realized oil price as a percentage of the NYMEX price in 2014 compared to the same period of 2013. Market data from

32 


     

third-party sources indicates the outlook for the basis differential between WTI-Midland and WTI-Cushing is approximately $6.50 per Bbl during the fourth quarter of 2014 and declines to approximately $4.25 per Bbl during the first quarter of 2015.

 

Recent Events

 

2015 capital budget. In early November 2014, we announced our 2015 capital budget of approximately $3.0 billion, of which approximately 90 percent of the drilling and completion costs will be dedicated to horizontal drilling. Our 2015 capital program is expected to continue focusing on drilling in the Delaware Basin and Midland Basin. The 2015 capital budget, based on our current expectations of commodity prices and cost, will exceed our cash flow. We expect our cash flow 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, we may adjust our capital budget to preserve financial strength.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

 

 

 

 

Capital

(in billions)

  

 

Budget

 

 

 

 

 

 

 

Drilling and completion costs:

  

 

 

 

Delaware Basin

  

$

 1.7  

 

Texas Permian

  

 

 0.6  

 

New Mexico Shelf

  

 

 0.4  

 

 

Total drilling and completion costs

 

 

 2.7  

Other capital (a)

  

 

 0.3  

 

Total

  

$

 3.0  

  

  

 

 

 

 

 

(a)

Includes facilities, leasehold acquisitions, a midstream project, geological and geophysical data and other capital.

 

Weather event. Heavy rainfall and flooding during the latter part of September 2014 disrupted our operations, primarily in southeast New Mexico, causing shut-in production, road closures and drilling and completion delays. We estimate this weather-related downtime negatively impacted production for the three and nine months ended September 30, 2014 by approximately 2.0 MBoepd and 0.7 MBoepd, respectively. We estimate that during the three months ended September 30, 2014 approximately $0.7 million of repairs was due to this event. Additionally, for the fourth quarter of 2014 we estimate a 1.3 MBoepd negative impact on production and estimate that repairs related to this weather event will be approximately $5.5 million.

 

Common stock offering. In May 2014, we issued in a secondary public offering approximately 7.475 million shares of our common stock at $129.00 per share, and we received net proceeds of approximately $932.0 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and plan to use the remainder for general corporate purposes, including funding our three-year accelerated growth plan and capital commitments associated with the midstream joint venture.

 

Delaware Basin midstream agreements. On May 9, 2014, we signed an agreement to own 50 percent of a joint venture, Alpha Crude Connector, LLC (“ACC”), which will build a crude oil pipeline to gather and transport oil production in the northern Delaware Basin. Additionally, on May 9, 2014, we entered into a ten year Crude Petroleum Dedication and Transportation Agreement with ACC to transport our oil production in the northern Delaware Basin. We expect to receive improved price realizations on our crude oil subject to this dedication agreement due to reduced transportation costs and increased marketing influence due to concentrated volumes.

 

Amended and restated credit facility. On May 9, 2014, we amended and restated our credit facility, increasing our borrowing base from $3.0 billion to $3.25 billion, but maintaining the aggregate lender commitments at $2.5 billion. The maturity date of the amended and restated credit facility is May 9, 2019. We expensed approximately $4.3 million in capitalized deferred loan costs incurred with the previous credit facility.

33 


     

 

Derivative Financial Instruments

 

Derivative financial instrument exposure. At September 30, 2014, the fair value of our financial derivatives was a net asset of $85.8 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 September 30, 2014, we entered into the following additional oil basis swaps to hedge additional amounts of our estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Basis Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 1,395,000  

 

 1,288,500  

 

 782,000  

 

 552,000  

 

 4,017,500  

 

 

Price per Bbl

$

 (4.25) 

$

 (4.29) 

$

 (4.34) 

$

 (4.35) 

$

 (4.29) 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

34 


     

Results of Operations

 

The following table sets forth summary information concerning our production and operating data for the three and nine months ended September 30, 2014 and 2013. 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

 

Nine Months Ended

  

 

 

 

 

  

September 30,

 

September 30,

 

 

 

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and operating data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

  

 

 6,689  

 

 

 5,417  

 

 

 18,764  

 

 

 15,376  

 

 

Natural gas (MMcf)

  

 

 22,513  

 

 

 19,593  

 

 

 63,798  

 

 

 56,006  

 

 

Total (MBoe)

  

 

 10,441  

 

 

 8,683  

 

 

 29,397  

 

 

 24,710  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbl)

  

 

 72,707  

 

 

 58,880  

 

 

 68,733  

 

 

 56,322  

 

 

Natural gas (Mcf)

  

 

 244,707  

 

 

 212,967  

 

 

 233,692  

 

 

 205,150  

 

 

Total (Boe)

  

 

 113,492  

 

 

 94,375  

 

 

 107,682  

 

 

 90,514  

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 Average prices:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, without derivatives (Bbl)

  

$

 86.05  

 

$

 102.10  

 

$

 90.40  

 

$

 91.89  

 

 

Oil, with derivatives (Bbl) (a)

  

$

 88.19  

 

$

 92.89  

 

$

 89.33  

 

$

 89.12  

 

 

Natural gas, without derivatives (Mcf)

  

$

 5.54  

 

$

 5.10  

 

$

 5.79  

 

$

 4.91  

 

 

Natural gas, with derivatives (Mcf) (a)

  

$

 5.56  

 

$

 5.33  

 

$

 5.70  

 

$

 5.00  

 

 

Total, without derivatives (Boe)

  

$

 67.07  

 

$

 75.20  

 

$

 70.28  

 

$

 68.31  

 

 

Total, with derivatives (Boe) (a)

  

$

 68.48  

 

$

 69.98  

 

$

 69.39  

 

$

 66.78  

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

Operating costs and expenses per Boe:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses and workover costs

  

$

 8.26  

 

$

 7.77  

 

$

 8.17  

 

$

 7.59  

 

 

Oil and natural gas taxes

  

$

 5.21  

 

$

 6.08  

 

$

 5.53  

 

$

 5.70  

 

 

Depreciation, depletion and amortization

  

$

 24.58  

 

$

 23.11  

 

$

 24.35  

 

$

 22.57  

 

 

General and administrative

  

$

 5.06  

 

$

 4.70  

 

$

 5.11  

 

$

 5.06  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

  

 

 

  

September 30,

 

September 30,

 

 

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

  

 

 

 

 

 

 

 

 

Oil derivatives

 

$

 14,271  

 

$

 (49,864) 

 

$

 (20,067) 

 

$

 (42,528) 

 

 

 

Natural gas derivatives

 

 

 446  

 

 

 4,589  

 

 

 (6,107) 

 

 

 4,844  

 

 

 

 

Total

 

$

 14,717  

  

$

 (45,275) 

  

$

 (26,174) 

  

$

 (37,684) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

35 


     

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

 

 

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $700.3 million for the three months ended September 30, 2014, an increase of $47.4 million (7 percent) from $652.9 million for the three months ended September 30, 2013. This increase was primarily due to increased production due to our successful drilling efforts during 2013 and 2014 as well as an increase in the realized natural gas prices, offset partially by the decrease in realized oil prices. Specific factors affecting oil and natural gas revenues include the following:

 

·         total oil production was 6,689 MBbl  for the three months ended September 30, 2014, an increase  of 1,272 MBbl  (23 percent) from 5,417 MBbl  for the three months ended September 30, 2013

 

·         average realized oil price (excluding the effects of derivative activities) was $86.05 per Bbl during the three months ended September 30, 2014, a decrease of 16 percent  from $102.10  per Bbl during the three months ended September 30, 2013. For the three months ended September 30, 2014 and 2013, we realized approximately 88.4 percent and 96.4 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 September 30, 2014 and 2013, the market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $9.96 per Bbl and $0.27 per Bbl, respectively;

 

·         total natural gas production was 22,513 MMcf  for the three months ended September 30, 2014, an increase  of 2,920 MMcf  (15 percent) from 19,593 MMcf  for the three months ended September 30, 2013; and

 

·         average realized natural gas price (excluding the effects of derivative activities) was $5.54 per Mcf during the three months ended September 30, 2014, an increase of 9 percent  from $5.10 per Mcf during the three months ended September 30, 2013. For the three months ended September 30, 2014 and 2013, we realized approximately 140.3 percent and 143.7 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, approximately 50 to 65 percent of our total natural gas revenues were derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues historically, our realized natural gas price (excluding the effects of derivatives) has reflected a price greater than the related NYMEX natural gas price.

36 


     

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the three months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

 

Three Months Ended September 30,

 

 

 

 

 

2014

 

 

2013

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

 80,441  

 

$

 7.70  

 

$

 64,883  

 

$

 7.47  

Taxes:

  

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem

  

 

 4,867  

 

 

 0.47  

 

 

 5,610  

 

 

 0.65  

 

Production

  

 

 49,535  

 

 

 4.74  

 

 

 47,108  

 

 

 5.43  

Workover costs

  

 

 5,882  

 

 

 0.56  

 

 

 2,630  

 

 

 0.30  

 

 

Total oil and natural gas production expenses

  

$

 140,725  

 

$

 13.47  

  

$

 120,231  

 

$

 13.85  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 $80.4 million ($7.70 per Boe) for the three months ended September 30, 2014, which was an increase of $15.5 million (24 percent) from $64.9 million ($7.47 per Boe) for the three months ended September 30, 2013. The increase in lease operating expenses was primarily due to increased production associated with our wells successfully drilled and completed in 2013 and 2014. The increase in lease operating expenses per Boe was primarily due to expansion of our production in areas with underdeveloped infrastructure. We estimate that during the three months ended September 30, 2014 approximately $0.7 million of repairs was due to a heavy rainfall and flooding event.

 

Production taxes per unit of production were $4.74 per Boe during the three months ended September 30, 2014, a decrease of 13 percent from $5.43 per Boe during the three months ended September 30, 2013. The decrease was directly related to the decrease in oil prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 11 percent.

 

Workover expenses were approximately $5.9 million and $2.6 million for the three months ended September 30, 2014 and 2013, respectively. The 2014 and 2013 expenses related primarily to routine workovers performed to increase or restore production.

37 


     

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

  

 

September 30,

(in thousands)

  

2014

 

2013

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

 2,031  

 

$

 3,154  

Exploratory dry hole costs

  

 

 10,063  

 

 

 -    

Leasehold abandonments

  

 

 4,618  

 

 

 7,578  

Other

 

 

 270  

 

 

 260  

 

Total exploration and abandonments

  

$

 16,982  

  

$

 10,992  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our geological and geophysical expense primarily consists of the costs of acquiring and processing geophysical data and core analysis, mostly related to multiple seismic projects in our Delaware Basin and Texas Permian areas associated with our increase in drilling and exploration activity in those areas.

 

Our exploratory dry hole costs during the three months ended September 30, 2014 were primarily related to expensing unsuccessful wells drilled as part of our extension efforts in our Delaware Basin acreage.

 

For the three months ended September 30, 2014 and 2013, we recorded approximately $4.6 million and $7.6 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 September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

 

2014

 

2013

 

 

 

 

 

Per

 

 

 

Per

(in thousands, except per unit amounts)

 

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

 

$

252,076

 

$

24.14

 

$

196,477

 

$

22.63

Depreciation of other property and equipment

 

 

4,324

 

 

0.41

 

 

3,783

 

 

0.44

Amortization of intangible assets - operating rights

 

 

365

 

 

0.03

 

 

365

 

 

0.04

 

Total depletion, depreciation and amortization

 

$

256,765

 

$

24.58

 

$

200,625

 

$

23.11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil price used to estimate proved oil reserves at period end

 

$

95.56

 

 

 

 

$

91.69

 

 

 

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

 

$

4.24

 

 

 

 

$

3.60

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties was $252.1 million ($24.14 per Boe) for the three months ended September 30, 2014, an increase of $55.6 million (28 percent) from $196.5 million ($22.63 per Boe) for the three months ended September 30, 2013. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2013 and 2014 and higher depletion rates per Boe. The increase in depletion expense per Boe was primarily due to (i) drilling deeper, higher cost wells in less proven areas and (ii) increasing production in our newer asset areas, such as the Delaware Basin, where we have a higher depletion rate than our legacy assets, such as the New Mexico Shelf.

 

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.

 

Impairments of long-lived assets.  We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward  

38 


     

adjustments to the economically recoverable proved reserves associated with decreases in estimated realized oil and natural gas prices, we recognized a non-cash charge against earnings of approximately $15.5 million during the three months ended September 30, 2014, which was primarily attributable to non-core properties in our Delaware Basin area.

 

General and administrative expenses.  The following table provides components of our general and administrative expenses for the three months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

 45,389  

 

$

 4.35  

 

$

 35,114  

 

$

 4.04  

Non-cash stock-based compensation

  

 

 13,465  

 

 

 1.29  

 

 

 9,923  

 

 

 1.14  

Less: Third-party operating fee reimbursements

  

 

 (6,091) 

 

 

 (0.58) 

 

 

 (4,201) 

 

 

 (0.48) 

 

Total general and administrative expenses

  

$

 52,763  

 

$

 5.06  

  

$

 40,836  

 

$

 4.70  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses were approximately $52.8 million ($5.06 per Boe) for the three months ended September 30, 2014, an increase of $12.0 million (29 percent) from $40.8 million ($4.70 per Boe) for the three months ended September 30, 2013. 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.  The increase in total general and administrative expenses per Boe was primarily due to an increase in the number of employees and related personnel expenses in order to manage our increased activities, coupled with increasing salaries due to the highly competitive labor market, offset partially by increased production from our wells successfully drilled and completed in 2013 and 2014.

 

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 $6.1 million and $4.2 million during the three months ended September 30, 2014 and 2013, 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 period over period.

39 


     

Gain (loss) on derivatives not designated as hedges.  The following table sets forth the gain (loss) on derivatives not designated as hedges for the three months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

Oil derivatives

 

$

 316,559  

 

$

 (169,049) 

 

 

Natural gas derivatives

 

 

 9,670  

 

 

 439  

 

 

 

Total

 

$

 326,229  

 

$

 (168,610) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents our cash receipts from (payments on) derivatives for the three months ended September 30, 2014 and 2013:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

Oil derivatives

 

$

 14,271  

 

$

 (49,864) 

 

 

Natural gas derivatives

 

  

 446  

 

  

 4,589  

 

 

 

Total

 

$

 14,717  

 

$

 (45,275) 

 

 

 

 

 

 

 

 

 

 

 

 

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 September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

  

 

 

Three Months Ended

 

 

 

September 30,

(dollars in thousands)

 

2014

 

2013

 

 

 

 

 

 

 

 

Interest expense

  

$

 52,601  

 

$

 55,995  

Capitalized interest

 

 

 897  

 

 

 -    

 

Interest expense, excluding impact of capitalized interest

 

$

 53,498  

 

$

 55,995  

 

  

 

 

 

 

 

Weighted average interest rate - credit facility

 

 

 -    

 

 

2.9%

Weighted average interest rate - senior notes

 

 

5.9%

 

 

5.9%

 

Total weighted average interest rate

  

 

5.9%

 

 

5.8%

 

 

 

 

 

 

 

 

Weighted average credit facility balance

  

$

 -    

 

$

 173,222  

Weighted average senior notes balance

  

 

 3,350,000  

 

 

 3,350,000  

 

Total weighted average debt balance

  

$

 3,350,000  

 

$

 3,523,222  

 

 

 

 

 

 

 

 

 

40 


     

The decrease in the weighted average debt balance for the three months ended September 30, 2014 as compared to the corresponding period in 2013 was due to the repayment of our credit facility using a portion of the proceeds from our May 2014 equity offering. The decrease in interest expense was due to an overall decrease in the weighted average debt balance.

 

Income tax provisions.  We recorded an income tax expense of $186.4 million and $21.7 million for the three months ended September 30, 2014 and 2013, respectively. The effective income tax rates for the three months ended September 30, 2014 and 2013 were 37.9 percent and 41.6 percent, respectively. During the fourth quarter of 2013, we revised our estimated blended effective state rate to consider (a) New Mexico legislation passed that phases in a tax rate reduction from 7.6 percent to 5.9 percent in 2018 and (b) the apportionment factor for states in which we operate. Additionally, during the three months ended September 30, 2014 and 2013, we recorded expense of $0.7 million and $1.3 million, respectively, associated with revisions of estimates based on filing our 2013 and 2012 tax returns, respectively. During the three months ended September 30, 2014, the revision did not result in a significant change to our effective rate. During the three months ended September 30, 2013, the revision increased our effective rate by 2.4 percent from 39.2 percent.

41 


     

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

 

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $2,065.9 million for the nine months ended September 30, 2014, an increase of $378.1 million (22 percent) from $1,687.8 million for the nine months ended September 30, 2013. This increase was primarily due to increased production due to our successful drilling efforts during 2013 and 2014 as well as an increase in the realized natural gas prices, offset partially by the decrease in realized oil prices. Specific factors affecting oil and natural gas revenues include the following:

 

·         total oil production was 18,764 MBbl  for the nine months ended September 30, 2014, an increase  of 3,388 MBbl  (22 percent) from 15,376 MBbl  for the nine months ended September 30, 2013

 

·         average realized oil price (excluding the effects of derivative activities) was $90.40 per Bbl during the nine months ended September 30, 2014, a decrease of 2 percent  from $91.89  per Bbl during the nine months ended September 30, 2013. For the nine months ended September 30, 2014 and 2013, we realized approximately 90.7 percent and 93.6 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 nine months ended September 30, 2014 and 2013, the market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $7.28 per Bbl and $2.74 per Bbl;

 

·         total natural gas production was 63,798 MMcf  for the nine months ended September 30, 2014, an increase  of 7,792 MMcf  (14 percent) from 56,006 MMcf  for the nine months ended September 30, 2013; and

 

·         average realized natural gas price (excluding the effects of derivative activities) was $5.79 per Mcf during the nine months ended September 30, 2014, an increase of 18 percent  from $4.91 per Mcf during the nine months ended September 30, 2013. For the nine months ended September 30, 2014 and 2013, we realized approximately 131.3 percent and 133.1 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, approximately 50 to 65 percent of our total natural gas revenues were derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues historically, our realized natural gas price (excluding the effects of derivatives) has reflected a price greater than the related NYMEX natural gas price.

 

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

Nine Months Ended September 30,

 

 

 

 

2014

 

2013

 

 

 

 

 

 

 

 

Per

 

 

 

 

 

Per

(in thousands, except per unit amounts)

  

 

Amount

 

 

Boe

 

 

Amount

 

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

 226,944  

 

$

 7.72  

 

$

 174,844  

 

$

 7.08  

Taxes:

  

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem

  

 

 15,946  

 

 

 0.54  

 

 

 17,367  

 

 

 0.70  

 

Production

  

 

 146,593  

 

 

 4.99  

 

 

 123,511  

 

 

 5.00  

Workover costs

  

 

 13,110  

 

 

 0.45  

 

 

 12,573  

 

 

 0.51  

 

 

Total oil and natural gas production expenses

  

$

 402,593  

 

$

 13.70  

  

$

 328,295  

 

$

 13.29  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

42 


     

Lease operating expenses were $226.9 million ($7.72 per Boe) for the nine months ended September 30, 2014, which was an increase of $52.1 million (30 percent) from $174.8 million ($7.08 per Boe) for the nine months ended September 30, 2013. The increase in lease operating expenses was primarily due to increased production associated with our wells successfully drilled and completed in 2013 and 2014. The increase in lease operating expenses per Boe was primarily due to expansion of our production in areas with underdeveloped infrastructure.

 

Production taxes per unit of production were $4.99 per Boe during the nine months ended September 30, 2014, which is consistent with $5.00 per Boe during the nine months ended September 30, 2013.

 

Workover expenses were approximately $13.1 million and $12.6 million for the nine months ended September 30, 2014 and 2013, respectively. The 2014 and 2013 expenses related primarily to routine workovers performed to increase or restore production.

 

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

Nine Months Ended

 

 

 

September 30,

(in thousands)

  

2014

 

2013

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

 13,790  

 

$

 23,597  

Exploratory dry hole costs

  

 

 36,593  

 

 

 (1,915) 

Leasehold abandonments

 

 

 19,756  

 

 

 13,828  

Other

  

 

 506  

 

 

 2,287  

 

Total exploration and abandonments

  

$

 70,645  

  

$

 37,797  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our geological and geophysical expense primarily consists of the costs of acquiring and processing geophysical data and core analysis, mostly related to our Delaware Basin and Texas Permian areas. During the nine months ended September 30, 2013, we had multiple seismic projects ongoing, which were completed during the second half of 2013. These projects were related to our increase in drilling and exploration activity in the Delaware Basin and Texas Permian areas.

 

Our exploratory dry hole costs during the nine months ended September 30, 2014 were primarily related to (i) expensing unsuccessful wells drilled as part of our extension efforts in our Delaware Basin acreage and (ii) an unsuccessful horizontal lateral in the New Mexico Shelf area. Our negative exploratory dry hole costs for the nine months ended September 30, 2013 is a result of an overestimate in 2012, partially offset by expenses on an unsuccessful lateral on a horizontal well due to mechanical issues in the Delaware Basin area.

43 


     

Depreciation, depletion and amortization expense.  The following table provides components of our depreciation, depletion and amortization expense for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

Nine Months Ended September 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Per

 

 

 

 

 

Per

(in thousands, except per unit amounts)

  

 

Amount

 

 

Boe

 

 

Amount

 

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

  

$

 701,624  

  

$

 23.87  

  

$

 545,569  

  

$

 22.08  

Depreciation of other property and equipment

  

 

 12,882  

 

 

 0.44  

 

 

 11,110  

 

 

 0.45  

Amortization of intangible asset - operating rights

  

 

 1,096  

 

 

 0.04  

 

 

 1,096  

 

 

 0.04  

 

Total depletion, depreciation and amortization

  

$

 715,602  

  

$

 24.35  

  

$

 557,775  

  

$

 22.57  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties was $701.6 million ($23.87 per Boe) for the nine months ended September 30, 2014, an increase of $156.0 million (29 percent) from $545.6 million ($22.08 per Boe) for the nine months ended September 30, 2013. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2013 and 2014 and higher depletion rates per Boe. The increase in depletion expense per Boe was primarily due to (i) drilling deeper, higher cost wells in less proven areas and (ii) increasing production in our newer asset areas, such as the Delaware Basin, where we have a higher depletion rate than our legacy assets, such as the New Mexico Shelf.

 

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

 

Impairments of long-lived assets.  We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with decreases in estimated realized oil and natural gas prices, we recognized a non-cash charge against earnings of approximately $15.5 million during the nine months ended September 30, 2014, which was primarily attributable to non-core properties in our Delaware Basin area.

44 


     

General and administrative expenses.  The following table provides components of our general and administrative expenses for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

Nine Months Ended September 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

 132,473  

 

$

 4.51  

 

$

 113,327  

 

$

 4.59  

Non-cash stock-based compensation

  

 

 34,672  

 

 

 1.18  

 

 

 25,278  

 

 

 1.02  

Less: Third-party operating fee reimbursements

  

 

 (17,097) 

 

 

 (0.58) 

 

 

 (13,485) 

 

 

 (0.55) 

 

Total general and administrative expenses

  

$

 150,048  

 

$

 5.11  

 

$

 125,120  

 

$

 5.06  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses were approximately $150.0 million ($5.11 per Boe) for the nine months ended September 30, 2014, an increase of $24.9 million (20 percent) from $125.1 million ($5.06 per Boe) for the nine months ended September 30, 2013.

 

The increase in cash general and administrative expenses of approximately $19.1 million was primarily due to an increase in the number of employees and related personnel expenses of $25.0 million in order to manage our increased activities directly related to our increased drilling and exploration activities, reduced in part by an upward adjustment to our bonus accrual for services related to 2012 of approximately $5.9 million ($0.24 per Boe) included in 2013.  

 

The increase in non-cash stock-based compensation of approximately $9.4 million was primarily due to (a) an increase in the number of employees in order to manage our increased activities directly related to our increased drilling and exploration activities, and (b) a $2.3 million ($0.09 per Boe) net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two officer resignations included in 2013.

 

The increase in total general and administrative expenses per Boe was primarily due to (i) an increase in the number of employees and related personnel expenses in order to manage our increased activities and (ii) a $0.09 net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two officer resignations included in 2013, noted above, offset in part by (a) increased production from our wells successfully drilled and completed in 2013 and 2014, and (b) a $0.24 per Boe upward adjustment to our bonus accrual for services related to 2012 included in 2013, noted above.

 

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 $17.1 million and $13.5 million during the nine months ended September 30, 2014 and 2013, 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 period over period.

45 


     

Gain (loss) on derivatives not designated as hedges.  The following table sets forth the gain (loss) on derivatives not designated as hedges for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives not designated as hedges:

 

 

 

 

 

 

 

 

Oil derivatives

 

$

 128,684  

 

$

 (172,698) 

 

 

Natural gas derivatives

 

 

 (2,777) 

 

 

 15,395  

 

 

 

Total

 

$

 125,907  

 

$

 (157,303) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents our cash receipts from (payments on) derivatives for the nine months ended September 30, 2014 and 2013:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

 

September 30,

 

(in thousands)

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

Oil derivatives

 

$

 (20,067) 

 

$

 (42,528) 

 

 

Natural gas derivatives

 

  

 (6,107) 

 

  

 4,844  

 

 

 

Total

 

$

 (26,174) 

 

$

 (37,684) 

 

 

 

 

 

 

 

 

 

 

 

 

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 nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

September 30,

(dollars in thousands)

 

2014

 

2013

 

 

 

 

 

 

 

 

Interest expense

  

$

 164,124  

 

$

 162,180  

Capitalized interest

 

 

 897  

 

 

 -    

 

Interest expense, excluding impact of capitalized interest

  

$

 165,021  

 

$

 162,180  

 

 

  

 

 

 

 

 

Weighted average interest rate - credit facility

 

 

2.3%

 

 

2.3%

Weighted average interest rate - senior notes

 

 

5.9%

 

 

6.2%

 

Total weighted average interest rate

  

 

5.8%

 

 

5.8%

 

 

 

 

 

 

 

 

Weighted average credit facility balance

 

 

 176,245  

 

 

 330,571  

Weighted average senior notes balance

 

 

 3,350,000  

 

 

 3,039,630  

 

Total weighted average debt balance

 

$

 3,526,245  

 

$

 3,370,201  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

46 


     

The increase in the weighted average debt balance for the nine months ended September 30, 2014 as compared to the corresponding period in 2013 was due to capital expenditures in excess of our cash flows, primarily related to our drilling program. The increase in interest expense was due to an overall increase in the weighted average debt balance.

 

Loss on extinguishment of debt.  We recorded a loss on extinguishment of debt of $4.3 million and $28.6 million for the nine months ended September 30, 2014 and 2013, respectively. The 2014 amount represents the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.  The 2013 amount includes approximately $20.4 million associated with the premium paid for the tender and redemption of the 8.625% Notes, approximately $5.5 million of unamortized deferred loan costs associated with the 8.625% Notes and approximately $2.7 million of unamortized discount on the 8.625% Notes.

 

Income tax provisions.  We recorded an income tax expense of $248.8 million and $86.0 million for the nine months ended September 30, 2014 and 2013, respectively. The effective income tax rates for the nine months ended September 30, 2014 and 2013 were 37.9 percent and 39.3 percent, respectively. During the fourth quarter of 2013, we revised our estimated blended effective state rate to consider (a) New Mexico legislation passed that phases in a tax rate reduction from 7.6 percent to 5.9 percent in 2018 and (b) the apportionment factor for states in which we operate.

 

Income from discontinued operations, net of tax. In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.1 million. As a result of post-closing adjustments during the nine months ended September 30, 2013, we made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million. We recognized income from discontinued operations, net of tax of $12.1 million for the nine months ended September 30, 2013

47 


     

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 nine months ended September 30, 2014 and 2013 totaled $1,738.1  million and $1,360.8  million, respectively. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2014 expenditures were funded in part from borrowings under our credit facility and proceeds from our May 2014 equity offering, while the 2013 expenditures were funded in part from borrowings under our credit facility.

 

Delaware Basin midstream agreements. On May 9, 2014, we signed an agreement with an unrelated third party to own 50 percent of a new midstream joint venture. The joint venture was formed to build a crude oil pipeline to gather and transport production in the northern Delaware Basin. We expect the system to be operational in the second half of 2015.

 

Additionally, on May 9, 2014, we entered into a ten year crude petroleum dedication and transportation agreement with the joint venture. Under the terms of the agreement and subject to certain regulatory approvals, we are obligated to deliver oil production to the joint venture from a substantial portion of the properties that we currently operate in the northern Delaware Basin area, as well as oil production from future development of certain of our northern Delaware Basin acreage.

 

2014 capital budget. Our 2014 upstream capital budget is approximately $2.6 billion, excluding the costs of acquisitions other than customary leasehold purchases of acreage. The capital budget will exceed our cash flows from operations, and we expect our cash flow from operations, proceeds from our May 2014 equity offering and borrowings under our credit facility will be sufficient to fund our budgeted capital expenditure needs during 2014.

 

2015 capital budget. In early November 2014, we announced our 2015 capital budget of approximately $3.0 billion, of which approximately 90 percent of the drilling and completion costs will be dedicated to horizontal drilling. Our 2015 capital program is expected to continue focusing on drilling in the Delaware Basin and Midland Basin. The 2015 capital budget, based on our current expectations of commodity prices and cost, will exceed our cash flow. We expect our cash flow 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, we may adjust our capital budget to preserve financial strength.

 

Three-year accelerated growth plan. In 2013, we announced an accelerated drilling program for the next three years which we expect will double production by 2016. By accelerating activity across our assets, we believe that we can deliver average annual organic production growth over this three-year period in excess of our historical annual average while increasing oil mix and reducing leverage ratios.

 

We have historically attempted to fund our non-acquisition expenditures with cash on hand and cash flow as adjusted from time to time. During the remainder of 2014 and 2015, we plan to use our credit facility and proceeds from our May 2014 equity offering to fund such expenditures in excess of our operating 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 availability 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.

  

48 


     

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

September 30,

(in thousands)

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

 

Proved

 

$

 60,359  

 

$

2,376

 

Unproved (a)

 

 

 107,985  

 

 

58,832

 

 

Total property acquisition costs

  

$

 168,344  

 

$

61,208

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Included in the unproved property acquisition costs above are budgeted leasehold acreage acquisitions of $78.2 million and $58.7 million for the nine months ended September 30, 2014 and 2013, respectively.

 

 

 

 

 

 

 

 

 

 

 

Contractual obligations.  Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with executive officers, derivative liabilities, investment contributions related to ACC and other obligations. Since December 31, 2013, the material changes in our contractual obligations included a $251.9 million decrease in outstanding long-term debt, a $152.4 million decrease in cash interest expense on debt and a $66.8 million decrease in our net commodity derivative liability. We also plan to contribute an additional $70.0 million to ACC over the next 15 months. See Note H 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 nine months ended September 30, 2014.

 

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

 

Capital resources.  Our primary sources of liquidity have historically been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities), borrowings under our credit facility, and proceeds from bond and equity offerings. We believe our 2014 expected capital expenditures will exceed our 2014 cash flow, and we have funded, and expect to continue to fund, the shortfall with cash on hand and borrowings under our credit facility. We believe that we have adequate cash on hand and availability under our credit facility to fund any cash flow deficits.

  

49 


     

The following table summarizes our changes in cash and cash equivalents for the nine months ended September 30, 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

  

 

  

 

Nine Months Ended

 

 

 

 

September 30,

(in thousands)

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

  

$

 1,288,536  

 

$

 944,644  

Net cash used in investing activities

  

 

 (1,835,204) 

 

 

 (1,472,096) 

Net cash provided by financing activities

  

 

 645,511  

 

 

 524,594  

 

Net increase (decrease) in cash and cash equivalents

  

$

 98,843  

 

$

 (2,858) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow from operating activities. The increase in operating cash flows during the nine  months ended September 30, 2014 as compared to the same period in 2013 was primarily due to (i) an increase in oil and natural gas revenues of approximately $378.1 million, (ii) approximately $45.4 million of positive variances in operating assets and liabilities; offset in part by (i) cash increases in related oil and natural gas production costs of approximately $74.3 million and (ii) a cash increase in general and administrative expense of approximately $19.1 million.

 

Our net cash provided by operating activities included reductions of $60.8 million and $106.2 million for the nine  months ended September 30, 2014 and 2013, 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 nine months ended September 30, 2014 and 2013, we invested $1,754.8 million and $1,426.3 million, respectively, for capital expenditures on oil and natural gas properties. Also, cash flows used in investing activities increased during the nine months ended September 30, 2014 as compared to 2013 related to (i) contributions to our equity method investment of approximately $30.1 million during the nine months ended September 30, 2014 and (ii) $1.1 million of proceeds from dispositions of assets during the nine months ended September 30, 2014 compared to $15.2 million during the comparative period of 2013, offset in part by 2014 settlements paid on derivatives not designated as hedges of approximately $26.2 million during the nine months ended September 30, 2014 compared to payments of approximately $37.7 million during the nine months ended September 30, 2013.

 

Cash flow from financing activities. Net cash provided by financing activities was approximately $645.5 million and $524.6 million for the nine  months ended September 30, 2014 and 2013, respectively.

 

During the nine  months ended September 30, 2014 and 2013 we completed the following significant activities:

 

·         In May 2014, we issued in a secondary public offering 7.475 million shares of our common stock at $129.00 per share, and we received net proceeds of approximately $932.0 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and plan to use the remainder for general corporate purposes, including funding our three-year accelerated growth plan and capital commitments associated with the midstream joint venture.

 

·         In June 2013, we issued $850 million in aggregate principal amount of 5.5% senior notes due 2023 at 103.75 percent of par, for which we received net proceeds of approximately $867.8 million. We used a portion of the net proceeds from this offering to fund the tender offer and redemption of the 8.625% Notes at a price of 106.922 percent of the unpaid principal amount. The remaining proceeds were used to pay down amounts outstanding on the credit facility.

 

At September 30, 2014, our availability to borrow additional funds was $2.5  billion based on bank commitments of $2.5 billion

 

50 


     

On May 9, 2014, we amended and restated our credit facility, increasing our borrowing base from $3.0 billion to $3.25 billion, but maintaining the aggregate lender commitments at $2.5 billion. The maturity date of the amended and restated 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 what cost and terms. 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 short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At September 30, 2014, we had $98.9 million of cash on hand.

 

At September 30, 2014, the commitments under our credit facility were $2.5 billion, which provided us with $2.5 billion of available  borrowing capacity. Upon a redetermination, our $3.25 billion borrowing base could be substantially reduced. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity.

 

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 stable 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 September 30, 2014 was $8.5 billion, consisting of debt of $3.4 billion and stockholders’ equity of $5.1 billion. Our debt to book capitalization was 40 percent and 49  percent at September 30, 2014 and December 31, 2013, respectively. Our ratio of current assets to current liabilities was 0.87 to 1.0 at September 30, 2014 as compared to 0.69 to 1.0 at December 31, 2013.

 

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 to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the nine months ended September 30, 2014, we received an average of $90.40 per Bbl of oil and $5.79 per Mcf of natural gas before consideration of commodity derivative contracts compared to $91.89 per Bbl of oil and $4.91 per Mcf of natural gas in the nine months ended September 30, 2013. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

51 


     

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 nine months ended September 30, 2014. See our disclosure of critical accounting policies in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the United States Securities and Exchange Commission (the “SEC”) on February 20, 2014.

52 


     

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, 2013.

 

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 September 30, 2014, 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 obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we 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 G 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 September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase of

 

 

Decrease of

 

 

 

 

 

 

 

 

$10 per Bbl and

 

 

$10 per Bbl and

(in thousands)

 

$1 per MMBtu

 

 

$1 per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss):

 

 

 

 

 

 

Oil derivatives

$

 (292,577) 

 

$

 292,577  

 

Natural gas derivatives

 

 (29,189) 

 

 

 30,430  

 

 

Total

$

 (321,766) 

 

$

 323,007  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

53 


     

At September 30, 2014, we had (i) oil price swaps that settle on a monthly basis covering future oil production from October 1, 2014 through June 30, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from October 1, 2014 to December 31, 2015. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX oil price for the nine months ended September 30, 2014 was $99.65 per Bbl. At November 4, 2014, the NYMEX oil price was $77.19 per Bbl.

 

At September 30, 2014, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from October 1, 2014 to December 31, 2015, (ii) natural gas collars covering future natural gas production from October 1, 2014 to December 31, 2014 and (iii) natural gas basis swaps covering our basis differential between the El Paso Permian delivery point and the NYMEX-Henry Hub delivery point from October 1, 2014 to December 31, 2015. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX natural gas price for the nine months ended September 30, 2014 was $4.41 per MMBtu. At November 4, 2014, the NYMEX natural gas price was $4.13 per MMBtu.

 

A decrease in the average forward NYMEX oil and natural gas prices below those at September 30, 2014, would increase the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2014. Changes in the recorded fair value of the undesignated 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 September 30, 2014, would decrease the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2014. 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 nine months ended September 30, 2014 for our derivative instruments. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivative

 

 

 

 

 

 

 

 

Instruments

(in thousands)

Net Assets (Liabilities) (a)

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of contracts outstanding at December 31, 2013

 

$

 (66,233) 

 

 

Changes in fair values (b)

 

 

 125,907  

 

 

Contract maturities

 

 

 26,174  

 

Fair value of contracts outstanding at September 30, 2014

 

$

 85,848  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 available commitments.

 

We had no indebtedness outstanding under our credit facility at September 30, 2014.

54 


     

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 Rules 13a-15(e) and 15d-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 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 September 30, 2014 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.

55 


     

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, 2013, 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, 2013. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2013 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

 

 

 

 

 

 

 

 

 

 

 

July 1, 2014 - July 31, 2014

  

 6,949  

 

$

 143.90  

 

-

 

 

August 1, 2014 - August 31, 2014

  

 992  

 

$

 136.92  

 

-

 

 

September 1, 2014 - September 30, 2014

  

 329  

 

$

 130.37  

 

-

 

 

  

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 

  

  

 

 

 

 

 

 

 

 

 

56 


     

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).

 

 

 

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.

57 


     

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:

November 6, 2014

 

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 and Chief Financial Officer

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By

/s/  Brenda R. Schroer

 

 

 

 

 

 

 

 

 

Brenda R. Schroer

 

 

 

 

Vice President and Chief Accounting Officer

 

 

 

 

(Principal Accounting Officer)

58 


     

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).

 

 

 

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.