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 March 31, 2016

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 May 2, 2016: 131,550,680 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

29

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

47

 

 

 

 

Item 4. Controls and Procedures

49

 

 

 

PART II – OTHER INFORMATION:

50

 

 

 

 

Item 1. Legal Proceedings

50

 

 

 

 

Item 1A. Risk Factors

50

 

 

 

 

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

51

 

 

 

 

Item 6. Exhibits  

52

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 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, 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 “Part II, Item 1A, Risk Factors” in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2015, as well as those factors summarized below:

·         declines in the prices we receive for our oil and natural gas, or sustained depressed prices we receive, for our oil and natural gas;

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

·         drilling and operating risks;

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

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

·         the impact of potential changes in our credit ratings;

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

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

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

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

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

·         potential financial losses or earnings reductions from our commodity price risk-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 March 31, 2016 and December 31, 2015

1

 

 

Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015

2

 

 

Consolidated Statement of Stockholders’  Equity for the Three Months Ended March 31, 2016

3

 

 

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015

4

 

 

Condensed Notes to Consolidated Financial Statements

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

iii 


 

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

 

 

 

 

 

 

 

March 31,

 

 

December 31,

(in thousands, except share and per share amounts)

 

 

2016

 

 

2015

Assets

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

466,821

 

$

228,550

 

Accounts receivable, net of allowance for doubtful accounts:

 

 

 

 

 

 

 

 

Oil and natural gas

 

 

191,698

 

 

203,972

 

 

Joint operations and other

 

 

168,545

 

 

190,608

 

Derivative instruments

 

 

527,769

 

 

652,498

 

Prepaid costs and other

 

 

33,734

 

 

38,922

 

 

  

Total current assets

 

 

1,388,567

 

 

1,314,550

Property and equipment:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

 

16,217,487

 

 

15,846,307

 

Accumulated depletion and depreciation

 

 

(6,830,070)

 

 

(5,047,810)

 

 

Total oil and natural gas properties, net

 

 

9,387,417

 

 

10,798,497

 

Other property and equipment, net

 

 

182,473

 

 

178,450

 

 

Total property and equipment, net

 

 

9,569,890

 

 

10,976,947

Deferred loan costs, net

 

 

14,416

 

 

15,585

Intangible asset - operating rights, net

 

 

25,328

 

 

25,693

Inventory

 

 

19,311

 

 

19,118

Noncurrent derivative instruments

 

 

114,072

 

 

167,038

Other assets

 

 

154,937

 

 

122,945

 

Total assets

 

$

11,286,521

 

$

12,641,876

Liabilities and Stockholders’ Equity

Current liabilities:

 

 

 

 

 

 

 

Accounts payable - trade

 

$

20,751

 

$

13,200

 

Revenue payable

 

 

123,338

 

 

169,787

 

Accrued and prepaid drilling costs

 

 

267,235

 

 

228,523

 

Other current liabilities

 

 

193,624

 

 

184,910

 

 

  

Total current liabilities

 

 

604,948

 

 

596,420

Long-term debt

 

 

3,332,854

 

 

3,332,188

Deferred income taxes

 

 

1,046,796

 

 

1,630,373

Noncurrent derivative instruments

 

 

393

 

 

-

Asset retirement obligations and other long-term liabilities

 

 

142,758

 

 

140,344

Commitments and contingencies (Note 10)

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

Common stock, $0.001 par value; 300,000,000 authorized; 131,973,782 and

 

 

 

 

 

 

 

 

129,444,042 shares issued at March 31, 2016 and December 31, 2015, respectively

 

 

132

 

 

129

 

Additional paid-in capital

 

 

4,874,546

 

 

4,628,390

 

Retained earnings

 

 

1,325,161

 

 

2,345,641

 

Treasury stock, at cost; 409,076 and 306,061 shares at March 31, 2016 and

 

 

 

 

 

 

 

 

December 31, 2015, respectively

 

 

(41,067)

 

 

(31,609)

 

 

  

Total stockholders’ equity

 

 

6,158,772

 

 

6,942,551

 

Total liabilities and stockholders’ equity

 

$

11,286,521

 

$

12,641,876

 

 

 

 

 

 

 

 

 

 

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

  

1 


 

 

 

 

 

 

 

 

 

 

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands, except per share amounts)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

Oil sales

 

$

242,154

 

$

349,584

 

Natural gas sales

 

 

41,410

 

 

63,938

 

 

Total operating revenues

 

 

283,564

 

 

413,522

Operating costs and expenses:

 

 

 

 

 

 

 

Oil and natural gas production

 

 

114,957

 

 

125,535

 

Exploration and abandonments

 

 

22,860

 

 

5,755

 

Depreciation, depletion and amortization

 

 

310,082

 

 

267,205

 

Accretion of discount on asset retirement obligations

 

 

1,712

 

 

1,994

 

Impairments of long-lived assets

 

 

1,524,645

 

 

-

 

General and administrative (including non-cash stock-based compensation of $16,022 and

 

 

 

 

 

 

 

 

$15,495 for the three months ended March 31, 2016 and 2015, respectively)

 

 

53,795

 

 

58,801

 

Gain on derivatives

 

 

(79,842)

 

 

(115,340)

 

(Gain) loss on disposition of assets, net

 

 

(111,066)

 

 

39

 

 

Total operating costs and expenses

 

 

1,837,143

 

 

343,989

Income (loss) from operations

 

 

(1,553,579)

 

 

69,533

Other income (expense):

 

 

 

 

 

 

 

Interest expense

 

 

(54,138)

 

 

(53,569)

 

Other, net

 

 

(6,535)

 

 

(4,302)

 

 

Total other expense

 

 

(60,673)

 

 

(57,871)

Income (loss) before income taxes

 

 

(1,614,252)

 

 

11,662

 

Income tax (expense) benefit

 

 

593,772

 

 

(4,150)

Net income (loss)

 

$

(1,020,480)

 

$

7,512

Earnings per share:

 

 

 

 

 

 

 

Basic net income (loss)

 

$

(7.95)

 

$

0.07

 

Diluted net income (loss)

 

$

(7.95)

 

$

0.06

 

 

 

 

 

 

 

 

 

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

2 


 

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Stock

 

 

Additional

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

Issued

 

 

Paid-in

 

 

Retained

 

Treasury Stock

 

Stockholders’

(in thousands)

 

Shares

 

 

Amount

 

 

Capital

 

 

Earnings

 

Shares

 

 

Amount

 

 

Equity

BALANCE AT DECEMBER 31, 2015

 

129,444

 

$

129

 

$

4,628,390

 

$

2,345,641

 

306

 

$

(31,609)

 

$

6,942,551

 

Net loss

 

-

 

 

-

 

 

-

 

 

(1,020,480)

 

-

 

 

-

 

 

(1,020,480)

 

Common stock issued in business combination

 

2,214

 

 

2

 

 

230,826

 

 

-

 

-

 

 

-

 

 

230,828

 

Stock options exercised

 

1

 

 

1

 

 

10

 

 

-

 

-

 

 

-

 

 

11

 

Incentive plan activity

 

336

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Cancellation of restricted stock

 

(21)

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Stock-based compensation

 

-

 

 

-

 

 

16,022

 

 

-

 

-

 

 

-

 

 

16,022

 

Tax deficiency related to stock-based

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

compensation

 

-

 

 

-

 

 

(702)

 

 

-

 

-

 

 

-

 

 

(702)

 

Purchase of treasury stock

 

-

 

 

-

 

 

-

 

 

-

 

103

 

 

(9,458)

 

 

(9,458)

BALANCE AT MARCH 31, 2016

 

131,974

 

$

132

 

$

4,874,546

 

$

1,325,161

 

409

 

$

(41,067)

 

$

6,158,772

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

3 


 

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

 

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income (loss)

 

$

(1,020,480)

 

$

7,512

 

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

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

310,082

 

 

267,205

 

 

Accretion of discount on asset retirement obligations

 

 

1,712

 

 

1,994

 

 

Impairments of long-lived assets

 

 

1,524,645

 

 

-

 

 

Exploration and abandonments, including dry holes

 

 

20,652

 

 

2,700

 

 

Non-cash stock-based compensation expense

 

 

16,022

 

 

15,495

 

 

Deferred income taxes

 

 

(583,577)

 

 

(11,031)

 

 

(Gain) loss on disposition of assets, net

 

 

(111,066)

 

 

39

 

 

Gain on derivatives

 

 

(79,842)

 

 

(115,340)

 

 

Other non-cash items

 

 

5,282

 

 

2,612

 

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

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

68,701

 

 

35,731

 

 

 

Prepaid costs and other

 

 

(4,764)

 

 

649

 

 

 

Inventory

 

 

(219)

 

 

3

 

 

 

Accounts payable

 

 

7,536

 

 

3,119

 

 

 

Revenue payable

 

 

(44,335)

 

 

(77,105)

 

 

 

Other current liabilities

 

 

1,926

 

 

(7,334)

 

 

 

 

Net cash provided by operating activities

 

 

112,275

 

 

126,249

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Capital expenditures on oil and natural gas properties

 

 

(379,799)

 

 

(790,773)

 

Additions to property, equipment and other assets

 

 

(8,999)

 

 

(8,147)

 

Proceeds from the disposition of assets

 

 

292,013

 

 

-

 

Contributions to equity method investments

 

 

(25,000)

 

 

(20,000)

 

Net settlements received from derivatives

 

 

257,930

 

 

167,156

 

  

 

 

Net cash provided by (used in) investing activities

 

 

136,145

 

 

(651,764)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Proceeds from issuance of debt

 

 

-

 

 

739,000

 

Payments of debt

 

 

-

 

 

(878,500)

 

Exercise of stock options

 

 

11

 

 

57

 

Excess tax benefit (deficiency) from stock-based compensation

 

 

(702)

 

 

464

 

Net proceeds from issuance of common stock

 

 

-

 

 

741,184

 

Purchase of treasury stock

 

 

(9,458)

 

 

(3,151)

 

Decrease in bank overdrafts

 

 

-

 

 

(73,539)

 

  

 

 

Net cash provided by (used in) financing activities

 

 

(10,149)

 

 

525,515

 

  

 

 

Net increase in cash and cash equivalents

 

 

238,271

 

 

-

Cash and cash equivalents at beginning of period

 

 

228,550

 

 

21

Cash and cash equivalents at end of period

 

$

466,821

 

$

21

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Issuance of common stock for a business combination

 

$

230,828

 

$

-

 

 

 

 

 

 

 

 

 

 

 

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

 

 

4 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 1. Organization and nature of operations

 

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

 

Note 2. Summary of significant accounting policies

 

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

 

Reclassifications. Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or cash flows.

 

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, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value of business combinations, fair value of nonmonetary exchanges, 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, 2015 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, 2015.

 

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. At March 31, 2016, the Company had approximately $145.8 million of restricted cash in an account held by a trustee in connection with a tax-free exchange transaction. During April 2016, the cash amount was transferred to the Company. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

 

5 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Equity method investments. The Company owns a 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the membership interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months. The Company expects the option to become exercisable during the third quarter of 2016. 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 was approximately $122.9 million and $98.9 million at March 31, 2016 and December 31, 2015, respectively, and is included in other assets in the Company’s consolidated balance sheet. The equity loss for the three months ended March 31, 2016 and 2015 was approximately $1.0 million and $0.8 million, respectively, and is included in other expense in the Company’s consolidated statement of operations. During the three months ended March 31, 2015, the Company recorded $0.6 million of capitalized interest on its investment in ACC. ACC commenced partial operations in late 2015. The Company expects the system to be fully operational during 2016.

 

During 2015, the Company purchased a 25 percent membership interest in an entity, which is constructing a crude oil gathering and transportation system in the southern Delaware Basin. The system is expected to be completed and operational during 2016. The Company accounts for its investment under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment was approximately $18.9 million and $20.8 million at March 31, 2016 and December 31, 2015, respectively, and is included in other assets in the Company’s consolidated balance sheet. The equity loss for the three months ended March 31, 2016 was approximately $1.9 million.  

 

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

 

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $6.5 million and $6.4 million for the three months ended March 31, 2016 and 2015, respectively.

 

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

 

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

 

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018

6 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

and early adoption is permitted. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

 

In March 2016, the FASB issued ASU No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” which changes the accounting and presentation for share-based payment arrangements in the following areas: (i) recognition in the statement of operations of excess tax benefits and deficiencies; (ii) cash flow presentation of excess tax benefits and deficiencies; (iii) minimum statutory withholding thresholds and the classification on the cash flow statement of the withheld amounts; and (iv) an accounting policy election to recognize forfeitures as they occur. This guidance is effective for reporting periods beginning after December 15, 2016 and early adoption is permitted. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

7 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 3. Exploratory well costs

 

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

  

The following table reflects the Company’s net capitalized exploratory well activity during the three months ended March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

  

Three Months Ended

(in thousands)

 

  

March 31, 2016

 

 

 

 

 

 

 

 

Beginning capitalized exploratory well costs

 

 

 

 

$

116,198

 

Additions to exploratory well costs pending the determination of proved reserves

 

 

 

 

 

84,895

 

Reclassifications due to determination of proved reserves

 

 

 

 

 

(45,436)

 

Disposition of wells

 

 

 

 

 

(17,339)

Ending capitalized exploratory well costs

 

 

 

 

$

138,318

 

 

 

 

 

 

 

 

 

The following table provides an aging at March 31, 2016 and December 31, 2015 of capitalized exploratory well costs based on the date drilling was completed:

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

 

December 31,

(dollars in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

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

  

$

125,542

 

$

98,764

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

  

 

12,776

 

  

17,434

 

Total capitalized exploratory well costs

  

$

138,318

 

$

116,198

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

 

 

 

 

 

 

 

than one year

 

 

8

 

 

8

 

 

  

 

 

 

 

 

 

Delaware Basin project. At March 31, 2016, the Company had approximately $1.4 million of suspended well costs greater than one year recorded for a well that was initially drilled to monitor nearby wells and is also being used to determine the productivity potential of additional zones. At March 31, 2016, the Company also had approximately $6.0 million of suspended well costs greater than one year recorded for a well spud in late 2014 that tested multiple zones. Currently, the Company is evaluating results in the area to determine the most suitable lateral zone in which to complete. Both wells completed drilling in 2014.

 

Projects operated by others. At March 31, 2016, the Company had approximately $5.0 million of suspended well costs greater than one year recorded for five wells that are operated by others and waiting on completion. Two of these wells, with

8 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

suspended well costs totaling approximately $3.5 million, completed drilling in 2012 and are expected to be completed in 2016. The remaining three wells completed drilling in 2014 and are waiting on completion.

 

Texas Permian project. At March 31, 2016, the Company had approximately $0.3 million of suspended well costs recorded for a well that was initially drilled to monitor nearby pad wells. These costs became greater than one year old during the three months ended March 31, 2016.

 

Note 4. Acquisitions and divestitures

 

Asset acquisition. In March 2016, the Company completed an acquisition of 80 percent of a third-party seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, the Company issued to the seller approximately 2.2 million shares of common stock with an approximate value of $230.8 million, $146.2 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties.

 

Asset divestiture. In February 2016, the Company sold certain assets in the northern Delaware Basin for estimated proceeds of approximately $294.1 million, subject to customary post-closing adjustments, and recognized a pre-tax gain of approximately $111.1 million.

 

Note 5. Asset retirement obligations

 

The Companys asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Companys asset retirement obligation activity during the three months ended March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

(in thousands)

 

 

March 31, 2016

 

 

 

 

 

 

 

 

Asset retirement obligations, beginning of period

 

 

 

 

$

119,945

 

Liabilities incurred from new wells

  

 

 

 

  

460

 

Liabilities assumed in acquisitions

  

 

 

 

  

902

 

Accretion expense

  

 

 

 

  

1,712

 

Disposition of wells

 

 

 

 

 

(507)

 

Liabilities settled upon plugging and abandoning wells

  

 

 

 

  

(464)

Asset retirement obligations, end of period

 

 

 

 

$

122,048

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 6.  Stock incentive plan

 

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

 

A summary of the Company’s activity for the three months ended March 31, 2016 is presented below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted

 

Stock

 

Performance

 

 

 

 

Stock

 

Options

 

Units

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding at December 31, 2015

 

  

1,199,647

 

 

42,901

 

 

315,755

 

 

Awards granted (a)

 

  

155,706

 

 

-

 

 

161,361

 

 

Options exercised

 

  

-

 

 

(824)

 

 

-

 

 

Awards cancelled / forfeited

 

  

(20,884)

 

 

-

 

 

(2,909)

 

 

Lapse of restrictions

 

 

(124,629)

 

 

-

 

 

-

 

Outstanding at March 31, 2016

 

1,209,840

 

42,077

 

474,207

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Weighted average grant date fair value per share

 

$

91.19

 

$

-

 

$

114.81

 

 

 

 

  

 

 

 

 

 

 

 

 

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the three months ended March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31, 2016

 

 

 

 

 

 

Risk-free interest rate

 

1.31%

Range of volatilities

 

31.6% - 59.0%

 

 

 

 

 

 

 

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at March 31, 2016:

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2016

 

$

44,810

2017

 

  

37,003

2018

 

  

14,541

2019

 

  

1,102

2020

 

  

14

 

Total

  

$

97,470

 

 

 

 

 

10 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 7. Disclosures about fair value measurements

 

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

 

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

 

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

 

Level 3:     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.

11 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

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 March 31, 2016 and December 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2016

 

December 31, 2015

 

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

(in thousands)

 

Value

 

Value

 

Value

 

Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

641,841

 

$

641,841

 

$

819,536

 

$

819,536

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

393

 

$

393

 

$

-

 

$

-

 

 

$600 million 7.0% senior notes due 2021 (a)

 

$

592,729

 

$

606,000

 

$

592,414

 

$

595,500

 

 

$600 million 6.5% senior notes due 2022 (a)

 

$

591,834

 

$

606,000

 

$

591,549

 

$

579,000

 

 

$600 million 5.5% senior notes due 2022 (a)

 

$

593,117

 

$

589,500

 

$

592,899

 

$

553,500

 

 

$1,550 million 5.5% senior notes due 2023 (a)

 

$

1,555,174

 

$

1,542,875

 

$

1,555,326

 

$

1,453,005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The carrying value includes associated deferred loan costs and any premium.

             

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

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.

  

12 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at March 31, 2016 and December 31, 2015. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2016

 

 

 

 

 

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

 

$

-

 

$

551,755

 

$

-

 

$

551,755

 

$

(23,986)

 

$

527,769

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

121,559

 

  

-

 

  

121,559

 

  

(7,487)

 

  

114,072

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

 

(23,986)

 

 

-

 

 

(23,986)

 

 

23,986

 

 

-

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(7,880)

 

  

-

 

  

(7,880)

 

  

7,487

 

  

(393)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

641,448

 

$

-

 

$

641,448

 

$

-

 

$

641,448

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

Fair Value Measurements Using

 

 

 

Net

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

Gross

 

 

Fair Value

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

Amounts

 

 

Presented

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

Offset in the

 

 

in the

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

 

 

 

Consolidated

 

 

Consolidated

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

Total

 

 

Balance

 

 

Balance

(in thousands)

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

Sheet

 

 

Sheet

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

-

 

$

684,029

 

$

-

 

$

684,029

 

$

(31,531)

 

$

652,498

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

175,267

 

  

-

 

  

175,267

 

  

(8,229)

 

  

167,038

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(31,531)

 

  

-

 

  

(31,531)

 

  

31,531

 

  

-

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(8,229)

 

  

-

 

  

(8,229)

 

  

8,229

 

  

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

819,536

 

$

-

 

$

819,536

 

$

-

 

$

819,536

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Concentrations of credit risk. At March 31, 2016, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 for additional information regarding the Company’s derivative activities and counterparties.

14 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

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 periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties and its integrated assets, 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. 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. 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. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it 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 calculates the expected undiscounted future net cash flows of its long-lived assets and its integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) proved reserves and risk-adjusted probable and possible reserves, and (vii) other sources of income and expenses from integrated assets.

 

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. These are classified as Level 3 fair value assumptions.

 

As a result of the carrying amount of certain of the Company’s long-lived assets being less than their expected undiscounted future net cash flows, the Company recognized a non-cash charge against earnings for the amount by which the carrying amount exceeded the estimated fair value of the assets. The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated period:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

 

 

 

 

Carrying

 

 

Fair Value

 

 

Impairment

(in thousands)

 

 

 Amount 

 

 

(Level 3)

 

 

Expense

 

 

 

 

 

 

 

 

 

 

March 2016

 

$

3,437,612

 

$

1,912,967

 

$

1,524,645

 

 

 

 

 

 

 

 

 

 

 

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

 

Based on the factors above as of March 31, 2016, the Company determined that undiscounted future cash flows attributable to a certain depletion group indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows further decline.

15 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 8. Derivative financial instruments

 

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

 

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

 

The following table summarizes the gain reported in earnings related to the commodity derivative instruments for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

March 31,

 

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

Gain on derivatives:

 

 

 

 

 

 

 

 

Oil derivatives

 

$

71,140

 

$

110,280

 

 

Natural gas derivatives

 

 

8,702

 

 

5,060

 

 

 

Total

 

$

79,842

 

$

115,340

 

 

 

 

 

 

 

 

 

 

 

     The following table represents the Company’s net cash receipts from derivatives for the three months ended March 31, 2016 and 2015:

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

March 31,

 

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

Net cash receipts from derivatives:

 

 

 

 

 

Oil derivatives

 

$

251,127

 

$

160,186

 

 

Natural gas derivatives

 

  

6,803

 

  

6,970

 

 

 

Total

 

$

257,930

 

$

167,156

 

 

 

 

 

 

 

 

 

 

 

16 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Commodity derivative contracts at March 31, 2016. The following table sets forth the Company’s outstanding derivative contracts at March 31, 2016. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at March 31, 2016 are expected to settle by December 31, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

Oil Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2016:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

5,985,000

 

5,460,000

 

5,054,000

 

16,499,000

 

 

Price per Bbl

 

 

$

73.38

$

74.21

$

59.38

$

69.37

 

2017:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

4,594,000

 

4,358,000

 

3,825,000

 

3,825,000

 

16,602,000

 

 

Price per Bbl

$

60.61

$

60.97

$

51.97

$

51.97

$

56.72

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2016:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

5,914,000

 

5,520,000

 

5,060,000

 

16,494,000

 

 

Price per Bbl

 

 

$

(1.46)

$

(1.46)

$

(1.48)

$

(1.47)

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

4,140,000

 

4,064,000

 

3,036,000

 

3,036,000

 

14,276,000

 

 

Price per Bbl

$

(1.24)

$

(1.27)

$

(0.43)

$

(0.43)

$

(0.90)

Natural Gas Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

7,280,000

 

7,360,000

 

7,360,000

 

22,000,000

 

 

Price per MMBtu

 

 

$

3.02

$

3.02

$

3.02

$

3.02

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

17 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

At March 31, 2016, the Company had a net asset position of $641.4 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $106.7 million, $100.2 million, $59.1 million and $56.0 million with Barclays Bank PLC,  J.P. Morgan Chase Bank, Wells Fargo Bank, N.A. and Societe Generale, respectively.  

 

Note 9. Debt 

 

The Company’s debt consisted of the following at March 31, 2016 and December 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

 

December 31,

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

Credit facility

 

$

-

 

$

-

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

 

  

24,362

 

  

25,073

Deferred loan costs, net

 

 

(41,508)

 

 

(42,885)

 

Less: current portion

 

  

-

 

  

-

 

 

Total long-term debt

 

$

3,332,854

 

$

3,332,188

 

 

 

 

 

 

 

 

 

 

Credit facility. The Company’s credit facility, as amended and restated, has a maturity date of May 9, 2019. In April 2016, the Company completed its annual borrowing base review where it maintained its $2.5 billion in commitments from its bank group until the Company’s next scheduled borrowing base redetermination in May 2017. The Company’s current borrowing base is $2.8 billion, which is a reduction from its previous borrowing base of $3.25 billion.

 

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

 

At March 31, 2016, 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 March 31, 2016 were as follows:

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Remaining 2016

 

$

 

-

2017

 

 

 

-

2018

 

 

 

-

2019

 

 

 

-

2020

 

 

 

-

2021

 

 

 

600,000

Thereafter

 

 

 

2,750,000

 

Total

$

 

3,350,000

 

 

 

 

 

 

18 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Interest expense.  The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

 

March 31,

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

Cash payments for interest

  

$

42,490

 

$

46,007

Amortization of original issue premium

 

 

(711)

 

 

(673)

Amortization of deferred loan origination costs

 

 

2,546

 

 

2,463

Accretion expense

 

 

486

 

 

-

Net changes in accruals

 

 

9,579

 

 

6,982

 

Interest costs incurred

 

 

54,390

 

 

54,779

Less: capitalized interest

 

 

(252)

 

 

(1,210)

 

Total interest expense

 

$

54,138

 

$

53,569

 

 

 

 

 

 

 

 

 

 

 

 

Note 10. 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 $8.4 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 March 31, 2016 and December 31, 2015, the Company had $13.4 million accrued for estimated exposure. 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. 

19 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments and power commitments. The following table summarizes the Company’s commitments at March 31, 2016:

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2016

 

$

39,165

2017

 

 

24,191

2018

 

 

64,105

2019

 

 

17,635

2020

 

 

11,038

2021

 

 

7,297

Thereafter

 

 

37,514

 

Total

$

200,945

 

 

 

 

 

 

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 March 31, 2016 and 2015 were approximately $2.0 million and $1.9 million, respectively.

 

Future minimum lease commitments under non-cancellable operating leases at March 31, 2016 were as follows:

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

Remaining 2016

 

$

6,211

2017

 

 

8,313

2018

 

 

7,530

2019

 

 

6,059

2020

 

 

4,780

2021

 

 

4,097

Thereafter

 

 

994

 

Total

$

37,984

 

 

 

 

 

 

Note 11. Income taxes

 

The effective income tax rates were 36.8 percent and 35.6 percent for the three months ended March 31, 2016 and 2015, respectively. Total income tax expense (benefit) for the three months ended March 31, 2016 and 2015 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax income (loss) due primarily to state taxes and the impact of permanent differences between book and taxable income.  

20 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 12. Related party transactions

 

The following table summarizes amounts paid to and received from related parties and reported in the Company’s consolidated statements of operations for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

 

 

March 31,

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

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

 

$

1,145

 

$

1,694

 

 

 

 

 

 

 

 

 

 

 

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

 

$

160

 

$

523

 

 

 

 

 

 

 

 

 

 

 

Amounts received from certain officers of the Company (c)

 

$

16

 

$

15

 

 

 

 

 

 

 

 

 

 

 

 

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

 

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

 

(c)   Amounts include payments to the Company as a result of activity on oil and natural gas properties in which certain officers (or affiliated entities) have an interest.

 

 

21 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 13. Net income (loss) per share

 

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

 

The following table reconciles the Company’s net income (loss) from operations and income (loss) attributable to common stockholders to the basic and diluted earnings used to determine the Company’s net income (loss) per share amounts for the three months ended March 31, 2016 and 2015, respectively, under the two-class method:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

March 31,

(in thousands, except per share amounts)

2016

 

2015

 

 

 

 

 

 

 

 

Net income (loss) as reported

$

(1,020,480)

 

$

7,512

Participating basic earnings (a)

 

-

 

 

(74)

 

Basic income (loss) attributable to common stockholders

 

(1,020,480)

 

 

7,438

Reallocation of participating earnings

 

-

 

 

-

 

Diluted income (loss) attributable to common stockholders

$

(1,020,480)

 

$

7,438

 

 

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

Basic

$

(7.95)

 

$

0.07

 

Diluted

$

(7.95)

 

$

0.06

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

 

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

Weighted average common shares outstanding:

  

 

 

 

 

Basic

  

128,396

 

114,047

 

 

Dilutive common stock options

  

-

 

25

 

 

Dilutive performance units

  

-

 

411

 

Diluted

  

128,396

 

114,483

 

 

 

 

 

 

 

 

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


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

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.

 

Note 14. Subsidiary guarantors

 

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

 

See Note 9 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission (“SEC”), 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 March 31, 2016 and December 31, 2015, condensed consolidating statements of operations for the three months ended March 31, 2016 and 2015 and condensed consolidating statements of cash flows for the three months ended March 31, 2016 and 2015, 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

March 31, 2016

Unaudited

 

Condensed Consolidating Balance Sheet

March 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

  

 

 

  

 

 

Accounts receivable - related parties

  

$

8,741,696

 

$

927,203

 

$

(9,668,899)

 

$

-

Other current assets

  

 

607,022

 

 

781,545

 

 

-

 

 

1,388,567

Oil and natural gas properties, net

  

 

-

 

 

9,387,417

 

 

-

 

 

9,387,417

Property and equipment, net

  

 

-

 

 

182,473

 

 

-

 

 

182,473

Investment in subsidiaries

  

 

2,058,208

 

 

-

 

 

(2,058,208)

 

 

-

Other long-term assets

  

 

138,625

 

 

189,439

 

 

-

 

 

328,064

 

Total assets

  

$

11,545,551

  

$

11,468,077

  

$

(11,727,107)

  

$

11,286,521

 

 

  

 

 

  

 

 

  

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

  

 

 

  

 

 

Accounts payable - related parties

  

$

927,203

 

$

8,741,696

 

$

(9,668,899)

 

$

-

Other current liabilities

  

 

79,533

 

 

525,415

 

 

-

 

 

604,948

Long-term debt

  

 

3,332,854

 

 

-

 

 

-

 

 

3,332,854

Other long-term liabilities

  

 

1,047,189

 

 

142,758

 

 

-

 

 

1,189,947

Equity

  

 

6,158,772

 

 

2,058,208

 

 

(2,058,208)

 

 

6,158,772

 

Total liabilities and equity

  

$

11,545,551

  

$

11,468,077

  

$

(11,727,107)

  

$

11,286,521

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Balance Sheet

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

  

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

 

 

 

  

 

 

Accounts receivable - related parties

  

$

8,502,099

 

$

1,162,297

 

$

(9,664,396)

 

$

-

Other current assets

  

 

753,716

 

 

560,834

 

 

-

 

 

1,314,550

Oil and natural gas properties, net

  

 

-

 

 

10,798,497

 

 

-

 

 

10,798,497

Property and equipment, net

  

 

-

 

 

178,450

 

 

-

 

 

178,450

Investment in subsidiaries

  

 

3,698,485

 

 

-

 

 

(3,698,485)

 

 

-

Other long-term assets

  

 

182,623

 

 

167,756

 

 

-

 

 

350,379

 

Total assets

  

$

13,136,923

  

$

12,867,834

 

$

(13,362,881)

  

$

12,641,876

 

 

  

 

 

  

 

 

 

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

 

 

 

  

 

 

Accounts payable - related parties

  

$

1,162,297

 

$

8,502,099

 

$

(9,664,396)

 

$

-

Other current liabilities

  

 

69,514

 

 

526,906

 

 

-

 

 

596,420

Long-term debt

  

 

3,332,188

 

 

-

 

 

-

 

 

3,332,188

Other long-term liabilities

  

 

1,630,373

 

 

140,344

 

 

-

 

 

1,770,717

Equity

  

 

6,942,551

 

 

3,698,485

 

 

(3,698,485)

 

 

6,942,551

 

Total liabilities and equity

  

$

13,136,923

  

$

12,867,834

 

$

(13,362,881)

  

$

12,641,876

 

 

 

 

 

 

 

 

 

 

 

 

 

 

24 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

283,564

 

$

-

 

$

283,564

Total operating costs and expenses

  

 

79,316

 

 

(1,916,459)

 

 

-

 

 

(1,837,143)

 

Income (loss) from operations

  

 

79,316

 

 

(1,632,895)

 

 

-

 

 

(1,553,579)

Interest expense

  

 

(53,291)

 

 

(847)

 

 

-

 

 

(54,138)

Other, net

  

 

(1,640,277)

 

 

(6,535)

 

 

1,640,277

 

 

(6,535)

 

Loss before income taxes

  

 

(1,614,252)

 

 

(1,640,277)

 

 

1,640,277

 

 

(1,614,252)

Income tax benefit

  

 

593,772

 

 

-

 

 

-

 

 

593,772

 

Net loss

  

$

(1,020,480)

 

$

(1,640,277)

 

$

1,640,277

 

$

(1,020,480)

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

$

-

 

$

413,522

 

$

-

 

$

413,522

Total operating costs and expenses

  

 

114,604

 

 

(458,593)

 

 

-

 

 

(343,989)

 

Income (loss) from operations

  

 

114,604

 

 

(45,071)

 

 

-

 

 

69,533

Interest expense

  

 

(53,569)

 

 

-

 

 

-

 

 

(53,569)

Other, net

  

 

(49,373)

 

 

(4,302)

 

 

49,373

 

 

(4,302)

 

Income (loss) before income taxes

  

 

11,662

 

 

(49,373)

 

 

49,373

 

 

11,662

Income tax expense

  

 

(4,150)

 

 

-

 

 

-

 

 

(4,150)

 

Net income (loss)

  

$

7,512

 

$

(49,373)

 

$

49,373

 

$

7,512

 

 

 

 

 

 

 

 

 

 

 

 

 

 

25 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

Consolidating

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

  

$

(247,781)

 

$

360,056

 

$

-

 

$

112,275

Net cash flows provided by (used in) investing activities

 

 

257,930

 

 

(121,785)

 

 

-

 

 

136,145

Net cash flows used in financing activities

  

 

(10,149)

 

 

-

 

 

-

 

 

(10,149)

 

Net increase in cash and cash equivalents

  

 

-

 

 

238,271

 

 

-

 

 

238,271

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

228,550

 

 

-

 

 

228,550

 

Cash and cash equivalents at end of period

  

$

-

 

$

466,821

 

$

-

 

$

466,821

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 





Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in thousands)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

 

$

(766,210)

 

$

892,459

 

$

-

  

$

126,249

Net cash flows provided by (used in) investing activities

  

 

167,156

 

 

(818,920)

 

 

-

  

 

(651,764)

Net cash flows provided by (used in) financing activities

  

 

599,054

 

 

(73,539)

 

 

-

  

 

525,515

 

Net increase (decrease) in cash and cash equivalents

  

 

-

 

 

-

 

 

-

 

 

-

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

21

 

 

-

 

 

21

 

Cash and cash equivalents at end of period

  

$

-

 

$

21

 

$

-

 

$

21

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

26 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 15. Subsequent events

 

New commodity derivative contracts.  After March 31, 2016, the Company entered into the following oil price swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

684,000

 

545,000

 

767,000

 

512,000

 

2,508,000

 

 

Price per Bbl

$

46.14

$

46.38

$

46.36

$

46.48

$

46.33

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,635,000

 

1,635,000

 

1,635,000

 

1,635,000

 

6,540,000

 

 

Price per Bbl

$

48.42

$

48.42

$

48.42

$

48.42

$

48.42

Natural Gas Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

3,150,000

 

3,185,000

 

2,760,000

 

2,760,000

 

11,855,000

 

 

Price per MMBtu

$

3.00

$

3.00

$

3.00

$

3.00

$

3.00

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(b)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

27 


Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2016

Unaudited

 

Note 16. Supplementary information

 

Capitalized costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Oil and natural gas properties:

 

 

 

 

 

 

 

Proved

 

$

15,240,182

 

$

14,940,259

 

Unproved

 

 

977,305

 

 

906,048

 

Less: accumulated depletion

 

 

(6,830,070)

 

 

(5,047,810)

 

 

Net capitalized costs for oil and natural gas properties

 

$

9,387,417

 

$

10,798,497

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs incurred for oil and natural gas producing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

 

Proved

  

$

252,352

 

$

-

 

Unproved

  

 

138,640

 

 

16,013

Exploration

  

 

170,572

 

 

429,169

Development

  

 

83,104

 

 

301,744

 

Total costs incurred for oil and natural gas properties

  

$

644,668

 

$

746,926

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The table below provides the amount of asset retirement obligations included in the costs incurred table shown above:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Exploration costs

 

$

231

 

$

618

Development costs

  

 

229

 

 

935

 

Total asset retirement obligations

  

$

460

 

$

1,553

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

28 


     

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, exploration and production of oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends. We are also at the forefront of applying new technologies, such as horizontal drilling and enhanced completion techniques, throughout our three core operating areas: the New Mexico Shelf, the Delaware Basin and the Midland Basin. In the New Mexico Shelf, we primarily target the Yeso formation with horizontal drilling; in the Delaware Basin, we use horizontal drilling to target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale formation; and in the Midland Basin, we target the Wolfcamp and Spraberry formations with horizontal drilling. Oil comprised 59 percent of our 623.5 MMBoe of estimated proved reserves at December 31, 2015 and 63.8 percent of our 12.7 MMBoe of production for the three months ended March 31, 2016. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 93 percent of our proved developed producing PV-10 and 78.9 percent of our 7,636 gross wells at December 31, 2015. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

 

Financial and Operating Performance

 

Our financial and operating performance for the three months ended March 31, 2016 and 2015 included the following highlights:

 

·         Net loss was $1.0 billion ($(7.95) per diluted share) as compared to net income of $7.5 million ($0.06 per diluted share) for the first three months of 2016 and 2015, respectively. The decrease was primarily due to:

 

       $1.5 billion in impairments of long-lived assets during the three months ended March 31, 2016, primarily attributable to properties in our New Mexico Shelf area;

 

       $129.9 million decrease in oil and natural gas revenues as a result of a 36 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities), partially offset by a 7 percent increase in production;  

 

       $42.9 million increase in depreciation, depletion and amortization expense, primarily due to a higher rate per Boe and increased production associated with new wells that were successfully drilled and completed in 2015 and 2016;  

 

       $35.5 million decrease in the gain on derivatives during the three months ended March 31, 2016, as compared to 2015; and

 

       $17.1 million increase in exploration and abandonment expense due primarily to leasehold abandonments during the three months ended March 31, 2016 as compared to 2015;

 

partially offset by:

 

       $598.0 million change in our income tax provision due to the decrease in income before income taxes; and

  

29 


     

       $111.1 million increase in (gain) loss on disposition of assets, net primarily due to our February 2016 asset divestiture.

 

·         Average daily sales volumes increased by 6 percent to 139,482 Boe per day during the first three months of 2016, as compared to 132,187 Boe per day during the first three months of 2015. The increase is primarily attributable to our successful drilling and completion efforts during 2015 and 2016, offset by normal production declines.

 

·         Net cash provided by operating activities decreased by approximately $13.9 million to $112.3 million for the first three months of 2016, as compared to $126.2 million in the first three months of 2015, primarily due to a decrease in oil and natural gas revenues, partially offset by positive variances in working capital changes.

  

·         Cash increased by approximately $238.3 million during the first three months of 2016 primarily as a result of operating cash flows and our divestiture that closed in February 2016, partially offset by the cash consideration related to our asset acquisition that closed in March 2016.

 

Commodity Prices

 

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and natural gas liquids, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil, natural gas and natural gas liquids, include, but are not limited to:

 

·         continuing economic uncertainty worldwide;

 

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

 

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

 

·         technological advances affecting energy consumption and energy supply;

 

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

 

·         the level of global inventories;

 

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

 

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

 

·         the quality of the oil we produce;

 

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

 

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

 

·         the effect of energy conservation efforts;

 

·         the price and availability of alternative fuels; and

 

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

 

       the United States economy,

 

       weather conditions, and

 

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

 

30 


     

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 8 and 15 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 March 31, 2016 and additional derivative contracts entered into subsequent to March 31, 2016, respectively.

 

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were significantly lower during the comparable periods of 2016 measured against 2015. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2016 and 2015, as well as the high and low NYMEX prices for the same periods:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

 

 

 

March 31,

 

 

 

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Average NYMEX prices:

  

 

 

 

 

 

 

Oil (Bbl)

  

$

33.73

 

$

48.80

 

Natural gas (MMBtu)

  

$

1.99

 

$

2.82

 

 

 

  

 

 

 

 

 

High and Low NYMEX prices:

  

 

 

 

 

 

 

Oil (Bbl):

 

 

 

 

 

 

 

 

High

  

$

41.45

 

$

53.53

 

 

Low

  

$

26.21

 

$

43.46

 

Natural gas (MMBtu):

  

 

 

 

 

 

 

 

High

  

$

2.47

 

$

3.23

 

 

Low

  

$

1.64

 

$

2.58

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $46.03 and $35.70 per Bbl and $2.18 and $1.90 per MMBtu, respectively, during the period from March 31, 2016 to May 2, 2016. At May 2, 2016, the NYMEX oil price and NYMEX natural gas price were $44.78 per Bbl and $2.04 per MMBtu, respectively.

 

Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas and the value of the dry natural gas residue. For the three months ended March 31, 2016 and 2015 our realized natural gas prices (excluding the effects of derivatives) were below the related NYMEX natural gas price primarily due to a downward trend in the average Mont Belvieu price for a blended barrel of natural gas liquids. The average Mont Belvieu price was $14.48 per Bbl and $19.30 per Bbl during the three months ended March 31, 2016 and 2015, respectively, a decrease of 25 percent.

31 


     

Recent Events

 

2016 capital budget. In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion.

 

During 2016, our current intent is to adjust our capital spending to be within our cash flows, excluding unbudgeted acquisitions. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we expect to be able to use our (i) cash on hand, (ii) credit facility and (iii) other financing sources. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans. Our 2016 capital program is expected to continue focusing on horizontal drilling across all our core areas.

 

Asset acquisition. In March 2016, we completed an acquisition of 80 percent of a third-party seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, we issued to the seller approximately 2.2 million shares of common stock with an approximate value of $230.8 million, $146.2 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties.

 

Asset divestiture. In February 2016, we sold certain assets in the northern Delaware Basin for estimated proceeds of approximately $294.1 million, subject to customary post-closing adjustments, and recognized a pre-tax gain of approximately $111.1 million.

32 


     

Derivative Financial Instruments

 

Derivative financial instrument exposure. At March 31, 2016, the fair value of our financial derivatives was a net asset of $641.4 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 March 31, 2016, we entered into the following oil price swaps and natural gas price swaps to hedge additional amounts of our estimated future production:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

684,000

 

545,000

 

767,000

 

512,000

 

2,508,000

 

 

Price per Bbl

$

46.14

$

46.38

$

46.36

$

46.48

$

46.33

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,635,000

 

1,635,000

 

1,635,000

 

1,635,000

 

6,540,000

 

 

Price per Bbl

$

48.42

$

48.42

$

48.42

$

48.42

$

48.42

Natural Gas Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

3,150,000

 

3,185,000

 

2,760,000

 

2,760,000

 

11,855,000

 

 

Price per MMBtu

$

3.00

$

3.00

$

3.00

$

3.00

$

3.00

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The index prices for the oil price swaps are based on the NYMEX – West Texas  Intermediate (“WTI”) monthly

 

average futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(b)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

33 


     

Results of Operations

 

The following table sets forth summary information concerning our production and operating data for the three months ended March 31, 2016 and 2015. 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

  

 

 

 

 

  

March 31,

 

 

 

 

 

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

Production and operating data:

 

 

 

 

 

 

 

Net production volumes:

 

 

 

 

 

 

 

 

Oil (MBbl)

  

 

8,100

 

 

8,066

 

 

Natural gas (MMcf)

  

 

27,557

 

 

22,985

 

 

Total (MBoe)

  

 

12,693

 

 

11,897

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

Oil (Bbl)

  

 

89,011

 

 

89,622

 

 

Natural gas (Mcf)

  

 

302,824

 

 

255,389

 

 

Total (Boe)

  

 

139,482

 

 

132,187

 

 

 

 

 

  

 

 

 

 

 

 

 Average prices:

  

 

 

 

 

 

 

 

Oil, without derivatives (Bbl)

  

$

29.90

 

$

43.34

 

 

Oil, with derivatives (Bbl) (a)

  

$

60.90

 

$

63.20

 

 

Natural gas, without derivatives (Mcf)

  

$

1.50

 

$

2.78

 

 

Natural gas, with derivatives (Mcf) (a)

  

$

1.75

 

$

3.08

 

 

Total, without derivatives (Boe)

  

$

22.34

 

$

34.76

 

 

Total, with derivatives (Boe) (a)

  

$

42.66

 

$

48.81

 

 

 

 

 

  

 

 

 

 

 

 

Operating costs and expenses per Boe:

  

 

 

 

 

 

 

 

Lease operating expenses and workover costs

  

$

7.28

 

$

7.64

 

 

Oil and natural gas taxes

  

$

1.78

 

$

2.91

 

 

Depreciation, depletion and amortization

  

$

24.43

 

$

22.46

 

 

General and administrative

  

$

4.24

 

$

4.95

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Includes the effect of net cash receipts from derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

  

 

 

  

March 31,

 

 

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash receipts from derivatives:

  

 

 

 

 

 

 

 

 

Oil derivatives

 

$

251,127

 

$

160,186

 

 

 

Natural gas derivatives

 

 

6,803

 

 

6,970

 

 

 

 

Total

 

$

257,930

  

$

167,156

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The presentation of average prices with derivatives is a non-GAAP measure as a result of including the net cash receipts from 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.

 

 

 

 

 

 

34 


     

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

 

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $283.6 million for the three months ended March 31, 2016, a decrease of $129.9 million (31 percent) from $413.5 million for 2015. This decrease was primarily due to the decrease in realized oil and natural gas prices, partially offset by increased production due to our successful drilling efforts during 2015 and 2016 offset by normal production declines. Specific factors affecting oil and natural gas revenues include the following:

 

·         total oil production was 8,100 MBbl  for the three months ended March 31, 2016, an increase  of 34 MBbl  from 8,066 MBbl  for 2015

 

·         average realized oil price (excluding the effects of derivative activities) was $29.90 per Bbl during the three months ended March 31, 2016, a decrease of 31 percent  from $43.34  per Bbl during 2015. For the three months ended March 31, 2016, our crude oil price differential relative to NYMEX was $(3.83) per Bbl, or a realization of approximately 88.6 percent, as compared to a crude oil price differential relative to NYMEX of $(5.46) per Bbl, or a realization of approximately 88.8 percent, for 2015. We incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. Due to lower oil prices during the first quarter of 2016 as compared to 2015, these fixed deductions had a greater percentage impact on our realized oil price. Additionally, 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 March 31, 2016 and 2015, the average market basis differential between WTI-Midland and WTI-Cushing was a price benefit of $0.14 per Bbl and reduction of  $(1.98) per Bbl, respectively;

 

·         total natural gas production was 27,557 MMcf  for the three months ended March 31, 2016, an increase  of 4,572 MMcf  (20 percent) from 22,985 MMcf  for 2015; and

 

·         average realized natural gas price (excluding the effects of derivative activities) was $1.50 per Mcf during the three months ended March 31, 2016, a decrease of 46 percent  from $2.78 per Mcf during 2015. For the three months ended March 31, 2016 and 2015, we realized approximately 75.4 percent and 98.6 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas and the value of the dry natural gas residue. During the three months ended March 31, 2016 and 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to a downward trend in the average Mont Belvieu price for a blended barrel of natural gas liquids. The average Mont Belvieu price was $14.48 per Bbl and $19.30 per Bbl during the three months ended March 31, 2016 and 2015, respectively, a decrease of 25 percent.

 

During December 2015, a third-party natural gas processing plant located in the northern Delaware Basin became inoperable following an explosion. We estimate that this event negatively impacted production for the quarter ended March 31, 2016 by approximately 4.5 MBoepd. We do not expect the plant to be back to full capacity until sometime during the second quarter of 2016.

  

35 


     

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

 

Three Months Ended March 31,

 

 

 

 

 

2016

 

 

2015

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

87,052

 

$

6.86

 

$

83,658

 

$

7.03

Workover costs

  

 

5,380

 

 

0.42

 

 

7,211

 

 

0.61

Taxes:

  

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem

  

 

5,522

 

 

0.44

 

 

5,255

 

 

0.44

 

Production

  

 

17,003

 

 

1.34

 

 

29,411

 

 

2.47

 

 

Total oil and natural gas production expenses

  

$

114,957

 

$

9.06

  

$

125,535

 

$

10.55

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 $87.1 million ($6.86 per Boe) for the three months ended March 31, 2016, which was an increase of $3.4 million from $83.7 million ($7.03 per Boe) for the three months ended March 31, 2015. During the first quarter of 2016, we experienced a slight increase in lease operating expenses due primarily to additional producing wells during the period as compared 2015, partially offset by a more favorable vendor pricing environment. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies.

 

Workover expenses were approximately $5.4 million and $7.2 million for the three months ended March 31, 2016 and 2015, respectively. The decrease was primarily related to less overall activity during 2016 as compared to 2015 and a more favorable vendor pricing environment.

 

Production taxes per unit of production were $1.34 per Boe during the three months ended March 31, 2016, a decrease of 46 percent from $2.47 per Boe during 2015. The decrease was directly related to the decrease in oil and natural gas prices and due to tax credits of approximately $3.7 million received during the first quarter of 2016 related to certain wells in Texas qualifying for reduced severance tax rates. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 36 percent.

  

36 


     

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

  

 

March 31,

(in thousands)

  

2016

 

2015

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

1,348

 

$

1,432

Exploratory dry hole costs

  

 

-

 

 

781

Leasehold abandonments

  

 

20,652

 

 

1,919

Other

 

 

860

 

 

1,623

 

Total exploration and abandonments

  

$

22,860

  

$

5,755

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis.

 

For the three months ended March 31, 2016 and 2015, we recorded approximately $20.7 million and $1.9 million, respectively, of leasehold abandonments. For the three months ended March 31, 2016, our abandonments were primarily related to acreage in our New Mexico Shelf area in locations where we have no future plans to drill.

 

Depreciation, depletion and amortization expense.   The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

2016

 

2015

 

 

 

 

 

Per

 

 

 

Per

(in thousands, except per unit amounts)

 

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

 

$

304,745

 

$

24.01

 

$

262,280

 

$

22.05

Depreciation of other property and equipment

 

 

4,972

 

 

0.39

 

 

4,560

 

 

0.38

Amortization of intangible assets - operating rights

 

 

365

 

 

0.03

 

 

365

 

 

0.03

 

Total depletion, depreciation and amortization

 

$

310,082

 

$

24.43

 

$

267,205

 

$

22.46

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil price used to estimate proved oil reserves at period end

 

$

42.77

 

 

 

 

$

79.21

 

 

 

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

 

$

2.40

 

 

 

 

$

3.88

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties was $304.7 million ($24.01 per Boe) for the three months ended March 31, 2016, an increase of $42.4 million (16 percent) from $262.3 million ($22.05 per Boe) for 2015. The increase in depletion expense was primarily due to  a higher depletion rate per Boe in addition to increased production associated with new wells that were successfully drilled and completed in 2015 and 2016. The increase in depletion expense per Boe period over period was primarily due to a decrease in proved reserves caused by (i) lower commodity prices period over period and (ii) reclassification of proved reserves to unproven that are no longer expected to be developed within the five years of their initial recording required by SEC rules during the fourth quarter of 2015, partially offset by a reduction in the net book value of our oil and natural gas properties due to a non-cash impairment charge of approximately $52.9 million recorded in the fourth quarter of 2015.

 

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.

 

37 


     

Impairments of long-lived assets. We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, 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. We review our oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. 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. If the estimated undiscounted future net cash flows are less than the carrying amount of our assets, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

 

We calculate the expected undiscounted future net cash flows of our long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) proved reserves and risk-adjusted probable and possible reserves, and (vii) other sources of income and expenses from integrated assets.

 

We calculate the estimated fair values of our long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.

 

As a result of the carrying amount of certain of our long-lived assets and their integrated assets being less than their expected undiscounted future net cash flows, we recognized a non-cash charge against earnings for the amount by which the carrying amount exceeded the estimated fair value of the assets. For the three months ended  March 31, 2016, this amount was approximately $1.5 billion and was primarily attributable to properties in our New Mexico Shelf area.

 

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

 

Based on economic factors as of March 31, 2016, we determined that undiscounted future cash flows attributable to a certain depletion group with net book value of approximately $1.8 billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) subsequent to March 31, 2016. We estimate that, if this depletion group was to become impaired in a future period, we could recognize non-cash impairment in that period of approximately $1.0 billion.

  

38 


     

General and administrative expenses.  The following table provides components of our general and administrative expenses for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

2016

 

2015

 

 

 

 

 

 

Per

 

 

 

 

Per

(in thousands, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

44,279

 

$

3.49

 

$

49,670

 

$

4.18

Non-cash stock-based compensation

  

 

16,022

 

 

1.26

 

 

15,495

 

 

1.30

Less: Third-party operating fee reimbursements

  

 

(6,506)

 

 

(0.51)

 

 

(6,364)

 

 

(0.53)

 

Total general and administrative expenses

  

$

53,795

 

$

4.24

  

$

58,801

 

$

4.95

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses were approximately $53.8 million ($4.24 per Boe) for the three months ended March 31, 2016, a decrease of $5.0 million (9 percent) from $58.8 million ($4.95 per Boe) for 2015. This decrease was primarily a result of a general company-wide initiative to reduce general and administrative costs. The decrease in total general and administrative expenses per Boe was primarily due to the company-wide initiative to reduce general and administrative costs noted above and increased production from our wells successfully drilled and completed in 2015 and 2016.

 

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 $6.5 million and $6.4 million during the three months ended March 31, 2016 and 2015, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

39 


     

Gain on derivatives.  The following table sets forth the gain on derivatives for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

Gain on derivatives:

 

 

 

 

 

 

 

Oil derivatives

 

$

71,140

 

$

110,280

 

Natural gas derivatives

 

 

8,702

 

 

5,060

 

 

Total

 

$

79,842

 

$

115,340

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     The following table represents our net cash receipts from derivatives for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

Net cash receipts from derivatives:

 

 

 

 

Oil derivatives

 

$

251,127

 

$

160,186

 

Natural gas derivatives

 

  

6,803

 

  

6,970

 

 

Total

 

$

257,930

 

$

167,156

 

 

 

 

 

 

 

 

 

 

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.

 

Gain on disposition of assets, net. In February 2016, we sold certain assets in the northern Delaware Basin for estimated proceeds of approximately $294.1 million, subject to customary post-closing adjustments, and recognized a pre-tax gain of approximately $111.1 million.

 

Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

  

 

 

Three Months Ended

 

 

 

March 31,

(dollars in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

Interest expense

  

$

54,138

 

$

53,569

Capitalized interest

 

 

252

 

 

1,210

 

Interest expense, excluding impact of capitalized interest

 

$

54,390

 

$

54,779

 

  

 

 

 

 

 

Weighted average interest rate - credit facility

 

 

-

 

 

2.4%

Weighted average interest rate - senior notes

 

 

5.9%

 

 

5.9%

 

Total weighted average interest rate

  

 

5.9%

 

 

5.7%

 

 

 

 

 

 

 

 

Weighted average credit facility balance

  

$

-

 

$

252,528

Weighted average senior notes balance

  

 

3,350,000

 

 

3,350,000

 

Total weighted average debt balance

  

$

3,350,000

 

$

3,602,528

 

 

 

 

 

 

 

 

 

40 


     

The decrease in the weighted average debt balance for the three months ended March 31, 2016 as compared to 2015 was due to the repayment of our credit facility using a portion of the proceeds from our October 2015 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 benefit of $593.8 million and income tax expense of $4.2 million for the three months ended March 31, 2016 and 2015, respectively. The change in our income tax provision was primarily due to the decrease in income before income taxes. The effective income tax rates for the three months ended March 31, 2016 and 2015 were 36.8 percent and 35.6 percent, respectively.

41 


     

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 ventures 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 three months ended March 31, 2016 and 2015 totaled $253.2 million and $729.4 million, respectively. The decrease was primarily due to our reduced drilling and completion activity level during the first quarter of 2016 as compared to the first quarter of 2015. The decrease is primarily related to our intent to adjust our capital spending to be within our cash flow, excluding unbudgeted acquisitions. The primary reason for the differences in the costs incurred and cash flow expenditures was our issuance of approximately 2.2 million shares of common stock related to our March 2016 acquisition and timing of payments. The 2016 expenditures were primarily funded in part from (i) cash flows from operations, (ii) proceeds from our February 2016 divestiture and (iii) our issuance of approximately 2.2 million shares of common stock related to our March 2016 acquisition.

 

2016 capital budget.  In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion.

 

During 2016, our current intent is to adjust our capital spending to be within our cash flows, excluding unbudgeted acquisitions. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we expect to be able to use our (i) cash on hand, (ii) credit facility and (iii) other financing sources. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans. Our 2016 capital program is expected to continue focusing on horizontal drilling across all our core areas.

 

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

 

Proved

 

$

252,352

 

$

-

 

Unproved (a)

 

 

138,640

 

 

16,013

 

 

Total property acquisition costs (b)

  

$

390,992

 

$

16,013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Included in the unproved property acquisition costs above are budgeted leasehold acreage acquisitions of $16.2 million and $16.0 million for the three months ended March 31, 2016 and 2015, respectively.

 

(b)

Included in the three months ended March 31, 2016 are approximately $374.3 million of property acquisition costs related to our March 2016 unbudgeted acquisition.

 

 

 

 

 

 

 

 

 

 

 

Contractual obligations.  Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, purchase obligations, employment agreements with executive officers, derivative liabilities, investment contributions related to Alpha Crude Connecter, LLC, our other midstream entity in the southern Delaware Basin and other obligations. Since December 31, 2015, the changes in our contractual obligations are not material. See Note 9 of the

42 


     

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 three months ended March 31, 2016.

 

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

 

Capital resources.  Our primary sources of liquidity have been cash flows generated from (i) operating activities and cash settlements received from derivatives, (ii) borrowings under our credit facility, (iii) proceeds from bond and equity offerings and (iv) proceeds from the sale of assets. In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion. During 2016, our current intent is to adjust our capital spending to be within our cash flows, excluding unbudgeted acquisitions. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we could use our (i) cash on hand, (ii) credit facility and (iii) other financing sources to fund any cash flow deficits.

 

The following table summarizes our changes in cash and cash equivalents for the three months ended March 31, 2016 and 2015:

 

 

 

 

 

 

 

 

 

  

 

  

 

Three Months Ended

 

 

 

 

March 31,

(in thousands)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

  

$

112,275

 

$

126,249

Net cash provided by (used in) investing activities

  

 

136,145

 

 

(651,764)

Net cash provided by (used in) financing activities

  

 

(10,149)

 

 

525,515

 

Net increase in cash and cash equivalents

  

$

238,271

 

$

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow from operating activities. The decrease in operating cash flows during the three  months ended March 31, 2016 as compared to the same period in 2015 was primarily due to (i) a decrease in oil and natural gas revenues of approximately $129.9 million, partially offset by (i) approximately $73.7 million of positive variances in operating assets and liabilities, (ii) approximately $25.4 million decrease in cash taxes, (iii) approximately $10.6 million decrease in cash production expense and (iv) a cash decrease in general and administrative expense of approximately $5.5 million.

 

Our net cash provided by operating activities included a benefit of approximately $28.8 million and a reduction of approximately $44.9 million for the three  months ended March 31, 2016 and 2015, 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 three months ended March 31, 2016 and 2015, we invested approximately $0.4 billion and $0.8 billion, respectively, for capital expenditures on oil and natural gas properties. Additionally, we received approximately $292.0 million related to proceeds from the disposition of assets and approximately $257.9 million from settlements on derivatives during the three months ended March 31, 2016 as compared to $167.2 million from settlements on derivatives during the comparable period in 2015.

  

Cash flow from financing activities. Net cash used by financing activities was approximately $10.1 million for the three  months ended March 31, 2016, while during 2015 we had net cash provided by financing activities of approximately $525.5 million. Below is a description of our financing activities:

 

·         In March 2015, we issued shares of our common stock in a public offering and received net proceeds of approximately $741.2 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

 

·         During the first three months of 2015, we had net payments on our credit facility of $139.5 million.

 

43 


     

·         During the first three months of 2016, we had no outstanding borrowings under our credit facility.

 

At March 31, 2016, we had unused commitments of approximately $2.5 billion based on bank commitments of $2.5 billion. The maturity date of the credit facility is May 9, 2019.

 

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

 

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

 

Liquidity. Our principal sources of liquidity are cash on hand and available borrowing capacity under our credit facility. At March 31, 2016, we had approximately $466.8 million of cash on hand.

 

In April 2016, we completed our annual borrowing base review where we maintained our $2.5 billion in commitments from our bank group until our next scheduled borrowing base redetermination in May 2017. Our current borrowing base is $2.8 billion, which is a reduction from our previous borrowing base of $3.25 billion. There is no assurance that our borrowing base will not be further reduced, which could affect our liquidity. Upon a subsequent redetermination, our borrowing base could be substantially reduced.

 

We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

 

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 “Ba1” with a stable outlook. S&P and Moody’s consider many factors in determining our ratings including: the industry in which we operate, 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.

 

A downgrade in our credit ratings could negatively impact our costs of capital and our ability to effectively execute aspects of our strategy. Further, a downgrade in our credit ratings could affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations.

 

As of the filing of this Quarterly Report, no changes in our credit ratings have occurred since March 31, 2016; however, we cannot be assured that our credit ratings will not be downgraded in the future.

 

Book capitalization and current ratio   Our net book capitalization at March 31, 2016 was $9.0 billion, consisting of $0.5 billion of cash and cash equivalents, debt of $3.3 billion and stockholders’ equity of $6.2 billion. Our net debt to book capitalization was 32 percent and 31  percent at March 31, 2016 and December 31, 2015, respectively. Our ratio of current assets to current liabilities was 2.30 to 1.0 at March 31, 2016 as compared to 2.20 to 1.0 at December 31, 2015.

44 


     

 

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 three months ended March 31, 2016, we received an average of $29.90 per Bbl of oil and $1.50 per Mcf of natural gas before consideration of commodity derivative contracts compared to $43.34 per Bbl of oil and $2.78 per Mcf of natural gas in the three months ended March 31, 2015. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

45 


     

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 three months ended March 31, 2016. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the United States Securities and Exchange Commission (the “SEC”) on February 25, 2016.

 

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

 

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

 

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

 

In March 2016, the FASB issued ASU No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” which changes the accounting and presentation for share-based payment arrangements in the following areas: (i) recognition in the statement of operations of excess tax benefits and deficiencies; (ii) cash flow presentation of excess tax benefits and deficiencies; (iii) minimum statutory withholding thresholds and the classification on the cash flow statement of the withheld amounts; and (iv) an accounting policy election to recognize forfeitures as they occur. This guidance is effective for reporting periods beginning after December 15, 2016 and early adoption is permitted. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

  

46 


     

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, 2015.

 

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 March 31, 2016, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

 

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

 

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

 

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.  See Note 8 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 $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase of

 

 

Decrease of

 

 

 

 

 

 

 

 

$5.00 per Bbl and

 

 

$5.00 per Bbl and

(in thousands)

 

$0.50 per MMBtu

 

 

$0.50 per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss):

 

 

 

 

 

 

Oil derivatives

$

(164,503)

 

$

164,503

 

Natural gas derivatives

 

(9,778)

 

 

9,778

 

 

Total

$

(174,281)

 

$

174,281

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

47 


     

At March 31, 2016, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 1, 2016 through December 31, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from April 1, 2016 to December 31, 2017. The average NYMEX oil price for the three months ended March 31, 2016 was $33.73 per Bbl. At May 2, 2016, the NYMEX oil price was $44.78 per Bbl.

 

At March 31, 2016, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from April 1, 2016 to December 31, 2016. The average NYMEX natural gas price for the three months ended March 31, 2016 was $1.99 per MMBtu. At May 2, 2016, the NYMEX natural gas price was $2.04 per MMBtu.

 

A decrease in the average forward NYMEX oil and natural gas prices below those at March 31, 2016 would increase the fair value asset of our commodity derivative contracts from their recorded balance at March 31, 2016. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential increase in our fair value asset would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at March 31, 2016 would decrease the fair value asset of our commodity derivative contracts from their recorded balance at March 31, 2016. 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 for our derivative instruments during the three months ended March 31, 2016. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivative

 

 

 

 

 

 

 

 

Instruments

(in thousands)

Net Assets (Liabilities) (a)

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of contracts outstanding at December 31, 2015

 

$

819,536

 

 

Changes in fair values (b)

 

 

79,842

 

 

Contract maturities

 

 

(257,930)

 

Fair value of contracts outstanding at March 31, 2016

 

$

641,448

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

 

 

 

(b)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

 

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

 

We had no indebtedness outstanding under our credit facility at March 31, 2016.

48 


     

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at March 31, 2016 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control 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 control over financial reporting.

49 


     

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 risk factor set forth below and the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2015, 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 Disclosures 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, 2015, other than updating the risk factor below. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2015 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. The updated risk factor is as follows:

 

Future price declines could result in a reduction in the carrying value of our proved oil and natural gas properties, which could adversely affect our results of operations.

 

Declines in commodity prices may result in us having to make substantial downward adjustments to the value of our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our proved oil and natural gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and natural gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and natural gas properties, the carrying value may not be recoverable and therefore require a write-down. The primary factors that may affect management’s estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) cash flows from integrated assets and (v) results of future drilling activities. We may incur impairment charges in the future, which could materially adversely affect our results of operations in the period incurred.

 

Additionally, based on the factors above, as of March 31, 2016, we determined that undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $1.8 billion indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) subsequent to March 31, 2016. We estimate that, if this depletion group was to become impaired in a future period, we could recognize non-cash impairment in that period of approximately $1.0 billion.

50 


     

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

 

 

 

 

 

 

 

 

 

 

 

January 1, 2016 - January 31, 2016

  

91,668

 

$

91.67

 

-

 

 

February 1, 2016 - February 29, 2016

  

11,268

 

$

92.95

 

-

 

 

March 1, 2016 - March 31, 2016

  

79

 

$

104.76

 

-

 

 

  

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 

  

  

 

 

 

 

 

 

 

 

 

51 


     

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.

  

52 


     

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:

May 5, 2016

 

By

/s/  Timothy A. Leach          

 

 

 

 

 

 

 

 

 

Timothy A. Leach

 

 

 

 

Director, Chairman of the Board of Directors, Chief Executive

 

 

 

 

Officer and President

 

 

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By

/s/  Darin G. Holderness

 

 

 

 

 

 

 

 

 

Darin G. Holderness

 

 

 

 

Senior Vice President, Chief Financial Officer and Treasurer

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By

/s/  Brenda R. Schroer

 

 

 

 

 

 

 

 

 

Brenda R. Schroer

 

 

 

 

Vice President and Chief Accounting Officer

 

 

 

 

(Principal Accounting Officer)

53 


     

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.