Attached files

file filename
EX-32.1 - EX-32.1 - Cobalt International Energy, Inc.cie-ex321_11.htm
EX-32.2 - EX-32.2 - Cobalt International Energy, Inc.cie-ex322_10.htm
EX-31.1 - EX-31.1 - Cobalt International Energy, Inc.cie-ex311_13.htm
EX-31.2 - EX-31.2 - Cobalt International Energy, Inc.cie-ex312_12.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

x

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

For the quarterly period ended 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: 001‑34579

Cobalt International Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

(State or other jurisdiction of

incorporation or organization)

27‑0821169
(I.R.S. Employer Identification No.)

 

 

Cobalt Center

920 Memorial City Way, Suite 100

Houston, Texas

(Address of principal executive offices)

77024

(Zip code)

 

(713) 579‑9100

(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 x  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 x  No o

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

 

Large accelerated filer

x

 

Accelerated filer

o

Non-accelerated filer

o

(Do not check if a smaller reporting company)

Smaller reporting company

o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes o  No x

Number of shares of the registrant’s common stock outstanding at March 31, 2016: 415,073,274 shares.

 

 

 

 

 


 

 

TABLE OF CONTENTS

 

 

 

1

 


 

 

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains estimates and forward-looking statements, principally in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our 2015 Annual Report on Form 10-K filed on February 22, 2016, may adversely affect our results as indicated in forward-looking statements. You should read this Quarterly Report on Form 10-Q and the documents that we have filed as exhibits hereto completely and with the understanding that our actual future results may be materially different from what we expect.

Our estimates and forward-looking statements may be influenced by the following factors, among others:

 

·

the timing or occurrence of the closing of the sale of our interests in Block 20 and 21 offshore Angola;

 

·

our liquidity and ability to finance our exploration, appraisal, development, and acquisition activities;

 

·

volatility and recent severe declines in oil and gas prices;

 

·

our ability to successfully and efficiently execute our project appraisal, development and exploration activities;

 

·

lack or delay of partner, government and regulatory approvals related to our business or required pursuant to agreements we are party to;

 

·

changes in environmental, safety and health laws and regulations or the implementation or interpretation of those laws and regulations;

 

·

current and future government regulation of the oil and gas industry and our operations;

 

·

oil and gas production rates on our properties that are currently producing oil and gas;

 

·

projected and targeted capital expenditures and other costs and commitments;

 

·

uncertainties inherent in making estimates of our oil and natural gas data;

 

·

our and our partners’ ability to obtain permits to drill and develop our properties in the U.S. Gulf of Mexico;

 

·

termination of or intervention in concessions, licenses, permits, rights or authorizations granted by the United States, Angolan and Gabonese governments to us;

 

·

our dependence on our key management personnel and our ability to attract and retain qualified personnel;

 

·

the ability of the containment resources we have under contract to perform as designed or contain or cap any oil spill, blow-out or uncontrolled flow of hydrocarbons;

 

·

the availability and cost of developing appropriate oil and gas transportation and infrastructure;

 

·

military operations, civil unrest, disease, piracy, terrorist acts, wars or embargoes;

 

·

our vulnerability to severe weather events, especially tropical storms and hurricanes in the U.S. Gulf of Mexico;

 

·

the cost and availability of adequate insurance coverage;

2

 


 

 

 

·

the results or outcome of any legal proceedings or investigations we may be subject to; 

 

·

our ability to meet our obligations under our material agreements, including the agreements governing our indebtedness; and

 

·

other risk factors discussed in the “Risk Factors” section of our 2015 Annual Report on Form 10-K filed on February 22, 2016.

The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this Quarterly Report on Form 10-Q might not occur and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

 

 

3

 


 

 

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements.

COBALT INTERNATIONAL ENERGY, INC.

 

 

4

 


 

 

Cobalt International Energy, Inc.

Condensed Consolidated Balance Sheets

 

 

 

March 31,

2016

(Unaudited)

 

 

December 31,

2015

 

 

 

($ in thousands, except

per share data)

 

Assets

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

52,951

 

 

$

71,593

 

Restricted cash and cash equivalents

 

 

252,200

 

 

 

252,950

 

Joint interest and other receivables

 

 

37,070

 

 

 

54,709

 

Prepaid expenses and other current assets

 

 

35,507

 

 

 

43,881

 

Inventory

 

 

19,263

 

 

 

26,113

 

Short-term investments

 

 

701,716

 

 

 

885,994

 

Current assets held for sale

 

 

1,911,102

 

 

 

1,811,051

 

Total current assets

 

 

3,009,809

 

 

 

3,146,291

 

Property, plant, and equipment:

 

 

 

 

 

 

 

 

Oil and gas properties, successful efforts method of accounting, net of

   accumulated depletion of $2,825 and $0, as of March 31, 2016 and

   December 31, 2015, respectively

 

 

1,027,559

 

 

 

893,734

 

Other property and equipment, net of accumulated depreciation

   and amortization of $6,992 and $6,647, as of March 31, 2016 and

   December 31, 2015, respectively

 

 

4,803

 

 

 

2,202

 

Total property, plant, and equipment, net

 

 

1,032,362

 

 

 

895,936

 

Long-term restricted funds

 

 

9,053

 

 

 

 

Deferred income taxes

 

 

 

 

 

 

Other assets

 

 

15,759

 

 

 

18,992

 

Total assets

 

$

4,066,983

 

 

$

4,061,219

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Trade and other accounts payable

 

$

7,375

 

 

$

856

 

Accrued liabilities

 

 

156,671

 

 

 

126,323

 

Deferred Angola sales proceeds

 

 

250,000

 

 

 

250,000

 

Deferred income taxes

 

 

 

 

 

 

Current liabilities held for sale

 

 

233,797

 

 

 

250,839

 

Total current liabilities

 

 

647,843

 

 

 

628,018

 

Long-term debt

 

 

2,006,620

 

 

 

1,981,895

 

Asset retirement obligations

 

 

3,269

 

 

 

3,167

 

Other long-term liabilities

 

 

1,966

 

 

 

2,002

 

Total long-term liabilities

 

 

2,011,855

 

 

 

1,987,064

 

Stockholders’ Equity:

 

 

 

 

 

 

 

 

Common stock, $0.01 par value per share; 2,000,000,000 shares authorized,

   409,731,943 and 408,740,182 issued and outstanding as of March 31, 2016

   and December 31, 2015, respectively

 

 

4,098

 

 

 

4,088

 

Additional paid-in capital

 

 

4,171,850

 

 

 

4,164,097

 

Accumulated deficit

 

 

(2,768,663

)

 

 

(2,722,048

)

Total stockholders’ equity

 

 

1,407,285

 

 

 

1,446,137

 

Total liabilities and stockholders’ equity

 

$

4,066,983

 

 

$

4,061,219

 

 

See accompanying notes.

 

 

5

 


 

 

Cobalt International Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

 

 

($ in thousands, except per share data)

 

Oil and gas revenue:

 

 

 

 

 

 

 

 

Oil sales

 

$

1,611

 

 

$

 

Natural gas sales

 

 

25

 

 

 

 

Total oil and gas revenue

 

 

1,636

 

 

 

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

Seismic and exploration

 

 

(1,254

)

 

 

14,067

 

Dry hole expense and impairment

 

 

(3,977

)

 

 

19,897

 

Lease operating expense

 

 

956

 

 

 

 

General and administrative

 

 

19,137

 

 

 

17,730

 

Accretion expense

 

 

102

 

 

 

 

Depreciation and amortization

 

 

3,170

 

 

 

412

 

Total operating costs and expenses

 

 

18,134

 

 

 

52,106

 

Operating income (loss)

 

 

(16,498

)

 

 

(52,106

)

Other income (expense):

 

 

 

 

 

 

 

 

Interest income

 

 

1,338

 

 

 

1,660

 

Interest expense

 

 

(15,642

)

 

 

(20,020

)

Total other income (expense)

 

 

(14,304

)

 

 

(18,360

)

Net income (loss) from continuing operations before income tax

 

 

(30,802

)

 

 

(70,466

)

Income tax expense

 

 

 

 

 

 

Net income (loss) from continuing operations

 

$

(30,802

)

 

$

(70,466

)

Net income (loss) from discontinued operations, net of income tax

 

 

(15,813

)

 

 

(11,151

)

Net income (loss)

 

 

(46,615

)

 

 

(81,617

)

Basic and diluted income (loss) per share from continuing

   operations

 

$

(0.08

)

 

$

(0.17

)

Basic and diluted income (loss) per share from discontinued

   operations

 

$

(0.03

)

 

$

(0.03

)

Basic and diluted income (loss) per share

 

$

(0.11

)

 

$

(0.20

)

Basic and diluted weighted average common shares outstanding

 

 

409,260,489

 

 

 

408,508,154

 

 

See accompanying notes.

 

 

6

 


 

 

Cobalt International Energy, Inc.

Condensed Consolidated Statements of Changes in Stockholders’ Equity

(Unaudited)

 

 

 

Common

Stock

 

 

Additional

Paid-in

Capital

 

 

Accumulated Deficit

 

 

Total

 

 

 

($ in thousands)

 

Balance, December 31, 2015

 

$

4,088

 

 

$

4,164,097

 

 

$

(2,722,048

)

 

$

1,446,137

 

Equity based compensation

 

 

 

 

 

7,763

 

 

 

 

 

 

7,763

 

Common stock issued for restricted stock and stock options

 

 

10

 

 

 

(10

)

 

 

 

 

 

 

Net income (loss)

 

 

 

 

 

 

 

 

(46,615

)

 

 

(46,615

)

Balance, March 31, 2016

 

$

4,098

 

 

$

4,171,850

 

 

$

(2,768,663

)

 

$

1,407,285

 

 

See accompanying notes.

 

 

7

 


 

 

Cobalt International Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

 

 

($ in thousands)

 

Cash flows provided from operating activities

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(46,615

)

 

$

(81,617

)

Adjustments to reconcile net income (loss) to net cash used in operating activities:

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

3,170

 

 

 

412

 

Accretion expense

 

 

102

 

 

 

 

Loss from discontinued operations

 

 

15,813

 

 

 

11,151

 

Dry hole expense and impairment of unproved properties

 

 

(3,977

)

 

 

19,897

 

Equity based compensation

 

 

7,763

 

 

 

5,843

 

Amortization of premium (accretion of discount) on investments

 

 

905

 

 

 

4,837

 

Amortization of debt discount and debt issuance costs

 

 

24,901

 

 

 

19,868

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Joint interest and other receivables

 

 

17,639

 

 

 

(15,756

)

Inventory

 

 

6,849

 

 

 

857

 

Prepaid expense and other current assets

 

 

8,375

 

 

 

(14,971

)

Deferred charges and other

 

 

3,057

 

 

 

(11,815

)

Trade and other accounts payable

 

 

3,421

 

 

 

969

 

Accrued liabilities and other

 

 

31,414

 

 

 

(25,753

)

Net cash provided by (used in) operating activities—continuing operations

 

 

72,817

 

 

 

(86,078

)

Net cash provided by (used in) operating activities—discontinued operations

 

 

(50,815

)

 

 

68,898

 

Net cash provided by (used in) operating activities

 

 

22,002

 

 

 

(17,180

)

Cash flows from investing activities

 

 

 

 

 

 

 

 

Capital expenditures for other property and equipment

 

 

(2,946

)

 

 

(23

)

Exploratory wells drilling in process

 

 

(130,678

)

 

 

(51,645

)

Change in restricted funds

 

 

(8,302

)

 

 

(46,049

)

Proceeds from maturity of investment securities

 

 

570,582

 

 

 

372,350

 

Purchase of investment securities

 

 

(387,209

)

 

 

(65,582

)

Net cash provided by (used in) investing activities—continuing operations

 

 

41,447

 

 

 

209,051

 

Net cash provided by (used in) investing activities—discontinued operations

 

 

(82,091

)

 

 

(176,941

)

Net cash provided by (used in) investing activities

 

 

(40,644

)

 

 

32,110

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

Net cash provided by (used in) financing activities

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

 

(18,642

)

 

 

14,930

 

Cash and cash equivalents, beginning of period

 

 

71,593

 

 

 

246,705

 

Cash and cash equivalents, end of period

 

$

52,951

 

 

$

261,635

 

Cash paid for interest

 

$

208

 

 

$

 

Non-cash disclosures

 

 

 

 

 

 

 

 

Changes in accrued capital expenditures

 

$

5,791

 

 

$

(8,716

)

Transfer of investment securities to and from restricted funds

 

$

22,641

 

 

$

46,049

 

 

See accompanying notes.

8

 


 

 

Cobalt International Energy, Inc.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

1. Summary of Significant Accounting Policies

General

Cobalt International Energy, Inc. (the “Company”) is an independent exploration and production company with operations in the deepwater U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa.

On August 22, 2015, Cobalt International Energy Angola Ltd., a wholly-owned subsidiary of the Company, executed a purchase and sale agreement with Sociedade Nacional de Combustíveis de Angola—Empresa Pública (“Sonangol”) for the sale by the Company to Sonangol of the entire issued and outstanding share capital of its indirect wholly-owned subsidiaries CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold the Company’s 40% working interest in each of Block 20 and Block 21 offshore Angola (the “Angola Transaction”). The Angola Transaction is subject to Angolan government approvals. On February 29, 2016, the Company relinquished its working interest in Block 9. The Company’s working interests in Blocks 20 and 21 offshore Angola have been classified as “held for sale” on the consolidated balance sheet. The results of operations associated with Blocks 9, 20 and 21 offshore Angola have been presented as discontinued operations in the accompanying consolidated statement of operations. Historically, the Company’s Angolan subsidiaries constituted a significant portion of its West Africa segment. The Company’s operations in Gabon, which are deemed immaterial, have been combined with its United States segment and are reported as one segment.

The terms “Company,” “Cobalt,” “we,” “us,” “our,” “ours,” and similar terms refer to Cobalt International Energy, Inc. unless the context indicates otherwise.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the financial statements of Cobalt International Energy, Inc. and all of its wholly-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all periods presented.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be presented for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

Correction of Immaterial Errors

The accompanying unaudited condensed financial statements for the three months ended March 31, 2016 include a reduction of impairment charges related to the Heidelberg field totaling approximately $8.5 million related to the prior year. The amounts were not deemed material with respect to such prior year or the anticipated results and the trend of earnings for fiscal year 2016.

9

 


 

 

Recently Issued Accounting Standards

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease.  However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  The Company’s current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the lease.  The Company currently does not have any leases classified as financing leases.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  The Company has not yet fully determined or quantified the effect ASU 2016-02 will have on the Company’s financial statements.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718).  The objective of ASU 2016-09 is for simplification involving several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  ASU 2016-09 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted.  The Company has not yet fully determined or quantified the effect ASU 2016-09 will have on the Company’s financial statements. 

In April 2015, Financial Accounting Standards Board (FASB) amended Accounting Standard Codification Subtopic No. 835-30, Interest—Imputation of Interest (the “ASC Subtopic 835-30”). The amendments require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments. The amendments under ASC Subtopic 835-30 are effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. The adoption of ASU 2015-03 resulted in $32.9 million of unamortized debt issuance costs reclassified from long-term assets to a reduction in long-term liabilities as of December 31, 2015. The Company elected to continue to report unamortized debt issuance costs related to its Borrowing Base Facility Agreement as a long-term asset. The adoption of ASU 2015-03 did not affect the statements of operations or the statements of cash flows. See Note 9 for additional information.

In July 2015, the FASB issued Accounting Standards Update (ASU) 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. The Company adopted the amendments to ASC 2015-11 on January 1, 2016. The adoption of ASC 2015-11 did not have material impact on the Company’s financial statements.

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern (ASU 2014-15). The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on the Company’s financial statements.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  The Company has not determined the effect ASU 2014-09 will have on the recognition of its

10

 


 

 

revenue, if any, nor has the Company determined the method the Company will utilize upon adoption, which would be in the first quarter of 2018.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by the Company include (i) accruals related to expenses, (ii) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (iii) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

Investments

The Company’s policy on accounting for its investments, which consist entirely of debt securities, is based on the accounting guidance relating to “Accounting for Certain Investments in Debt and Equity Securities.” The Company considers all highly liquid interest-earning investments with a maturity of three months or less at the date of purchase to be cash equivalents. Investments with original maturities of greater than three months and remaining maturities of less than one year are classified as short-term investments. Investments with maturities beyond one year are classified as long-term investments. The debt securities are carried at cost, which approximates fair market value as of March 31, 2016 and December 31, 2015 and are classified as held-to-maturity as the Company has the positive intent and ability to hold them until they mature. The net carrying value of held-to-maturity securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. Income related to these securities is reported as a component of interest income in the Company’s condensed consolidated statement of operations. See Note 5—Investments.

Investments are considered to be impaired when a decline in fair value is determined to be other-than-temporary. The Company conducts a regular assessment of its debt securities with unrealized losses to determine whether securities have other-than-temporary impairment (“OTTI”). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether the Company intends to sell or whether it is more likely than not that the Company will be required to sell the debt securities. As of March 31, 2016 and December 31, 2015, the Company has no OTTI in its debt securities.

Property, Plant, and Equipment 

The Company uses the “successful efforts” method of accounting for its oil and gas properties. Acquisition costs for unproved leasehold properties and costs of drilling exploration wells are capitalized pending determination of whether proved reserves can be attributed to the areas as a result of drilling those wells. Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a units-of-production basis. Successful drilling costs, costs of development and developmental dry holes are capitalized and amortized over the proved developed reserves on a units-of-production basis. When circumstances indicate that proved oil and gas properties may be impaired, the Company compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on the Company's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. Significant unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine if an impairment of the cost of individual properties has occurred. Factors taken into account for impairment analysis include results of the technical studies conducted, lease terms and management’s future exploration plans. The cost of impairment is charged to expense in the period in which it occurs. Costs incurred for exploration dry holes, geological and geophysical work (including the cost of seismic data), and delay rentals are charged to expense as incurred. Costs of other property and equipment are depreciated on a straight-line basis based on their respective useful lives.

11

 


 

 

Asset Retirement Obligation

The Company expects to have significant obligations under its lease agreements and federal regulation to remove its equipment and restore land or seabed at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas platforms. Estimating the future restoration and removal cost is difficult and requires the Company to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and cost are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Bureau of Ocean Energy Management (“BOEM”) has proposed updated financial assurance requirements for offshore oil and gas leases in connection with operators’ decommissioning and abandonment liabilities for facilities in the U.S. Gulf of Mexico.  The Company expects the final requirements to be issued soon, and the Company may need to post additional financial assurances, including surety bonds, in connection with its operations or otherwise satisfy certain financial tests in order to comply.  Such requirements may increase the Company’s costs of operating in the U.S. Gulf of Mexico.  Pursuant to the accounting guidance relating to “Assets Retirement Obligations”, the Company is required to record a separate liability for the discounted present value of its asset retirement obligations, with an offsetting increase to the related oil and natural gas properties representing asset retirement costs on the balance sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate.

Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, the Company will make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted abandonment liability resulting from the passage of time will be reflected as additional accretion expense in the consolidated statement of operations.

The following summarizes the changes in the asset retirement obligation for the three months ended March 31, 2016:

 

 

 

March 31,

2016

 

 

 

($ in thousands)

 

Beginning of period

 

$

3,167

 

Liabilities incurred

 

 

 

Accretion

 

 

102

 

End of period

 

$

3,269

 

 

Capitalized Interest

For exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 7—Property, Plant, and Equipment and Note 9—Long-term Debt.

Earnings (Loss) Per Share

Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share includes the potential dilutive impact of non-vested restricted stock, non-vested restricted stock units, outstanding stock options, the 2.625% convertible senior notes due 2019 and the 3.125% convertible senior notes due 2024 during the period, unless their effect is anti-dilutive. For the three months ended March 31, 2016, 10,211,590 shares of non-vested restricted stock, non-vested restricted stock units, outstanding stock options, the 2.625% convertible senior notes due 2019 and the 3.125% convertible senior notes due 2024, were excluded from the diluted income (loss) per share calculation because they were anti-dilutive. For the three months ended March 31, 2015, 10,085,521 shares of non-vested restricted

12

 


 

 

stock, non-vested restricted stock units, outstanding stock options and the 2.625% convertible senior notes due 2019 and the 3.125% convertible senior notes due 2024, were excluded from the diluted income (loss) per share because they are anti-dilutive.

 

 

2. Cash and Cash Equivalents

Cash and cash equivalents consisted of the following:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Cash at banks

 

$

37,968

 

 

$

33,173

 

Held-to-maturity securities(1)

 

 

14,983

 

 

 

38,420

 

 

 

$

52,951

 

 

$

71,593

 

 

(1)

These securities mature three months or less from the date of purchase.

 

 

3. Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consisted of the following:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Angolan sale proceeds

 

$

250,000

 

 

$

250,000

 

American Express Bank pledge agreement

 

 

 

 

 

750

 

Citibank commercial card agreement

 

 

2,200

 

 

 

2,200

 

Total restricted funds(1)

 

$

252,200

 

 

$

252,950

 

 

(1)

Pursuant to the purchase and sale agreement governing the Angola Transaction, the Company received the First Payment of $250 million during the quarterly period ended September 30, 2015. See Note 10—Angola Transaction. These funds are contractually restricted by the purchase and sale agreement pending the closing of the Angola Transaction. In addition, as of March 31, 2016, approximately $2.2 million was held in collateral accounts established to pledge funds for security of obligations under the Citibank Commercial Card Agreement. As of March 31, 2016, the Angolan sales proceeds and collateral in these accounts were invested in cash, certificates of deposit, commercial paper, and money market funds, resulting in a net carrying value of approximately $252.2 million. The contractual maturities of these securities are within ninety days.

 

 

4. Joint Interest and Other Receivables

Joint interest and other receivables result primarily from billing shared costs under the respective operating agreements to the Company’s partners. These are usually settled within 30 days of the invoice date. As of March 31, 2016 and December 31, 2015, the balance in joint interest, revenue, and other receivables consisted of the following:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Partners in the U.S. Gulf of Mexico

 

$

33,833

 

 

$

50,766

 

Revenue receivable

 

 

1,150

 

 

 

 

Accrued interest on investment securities

 

 

1,597

 

 

 

3,567

 

Other

 

 

490

 

 

 

376

 

 

 

$

37,070

 

 

$

54,709

 

 

 

13

 


 

 

5. Investments

The Company’s investments in held-to-maturity securities, which are recorded at cost which approximates fair market value, were as follows as of March 31, 2016 and December 31, 2015:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Corporate securities

 

$

183,839

 

 

$

492,955

 

Commercial paper

 

 

677,878

 

 

 

604,986

 

U.S. Treasury securities

 

 

9,053

 

 

 

 

Certificates of deposit

 

 

10,000

 

 

 

20,750

 

Total

 

$

880,770

 

 

$

1,118,691

 

 

The Company’s condensed consolidated balance sheet included the following held-to-maturity securities:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Cash and cash equivalents

 

$

14,983

 

 

$

38,420

 

Short-term investments

 

 

701,716

 

 

 

885,994

 

Restricted cash and cash equivalents

 

 

155,018

 

 

 

194,277

 

Long-term restricted funds

 

 

9,053

 

 

 

 

 

 

$

880,770

 

 

$

1,118,691

 

 

The contractual maturities of these held-to-maturity securities as of March 31, 2016 and December 31, 2015 were as follows:

 

 

 

March 31, 2016

 

 

December 31, 2015

 

 

 

Carrying

Value

 

 

Estimated

Fair Value

 

 

Carrying

Value

 

 

Estimated

Fair Value

 

 

 

($ in thousands)

 

Within 1 year

 

$

880,770

 

 

$

880,770

 

 

$

1,118,691

 

 

$

1,118,691

 

After 1 year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

880,770

 

 

$

880,770

 

 

$

1,118,691

 

 

$

1,118,691

 

 

 

6. Fair Value Measurements

The fair values of the Company’s cash and cash equivalents, joint interest and other receivables, short-term restricted funds and investments approximate their carrying amounts due to their short-term duration. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. The Company categorizes each of its fair value measurements as applicable to one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. The levels are:

Level 1—Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. This category includes the Company’s cash and money market funds.

Level 2—Quoted prices in non-active markets or in active markets for similar assets or liabilities, and inputs other than quoted prices that are observable, for the asset or liability, either directly or indirectly, for substantially the full contractual term of the asset or liability being measured. This category includes the Company’s U.S. Treasury bills, U.S. Treasury notes, commercial paper, U.S. agency securities, corporate bonds, and certificates of deposits.

Level 3—Inputs that are generally unobservable and typically reflect management’s estimate of assumptions that market participants would use in pricing the asset or liability. The Company does not currently have any financial instruments categorized as Level 3.

14

 


 

 

The following tables summarize the Company’s significant financial instruments measured on a recurring basis as categorized by the fair value measurement hierarchy:

 

 

 

Level 1

 

 

Level 2

 

 

Balance as of

 

 

 

Carrying

Value

 

 

Fair

Value(1)

 

 

Carrying

Value

 

 

Fair

Value(1)

 

 

March 31,

2016

 

 

 

($ in thousands)

 

Cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash

 

$

37,968

 

 

$

37,968

 

 

$

 

 

$

 

 

$

37,968

 

Money market funds

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial paper

 

 

 

 

 

 

 

 

14,983

 

 

 

14,983

 

 

 

14,983

 

Subtotal

 

 

37,968

 

 

 

37,968

 

 

 

14,983

 

 

 

14,983

 

 

 

52,951

 

Restricted cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

 

97,182

 

 

 

97,182

 

 

 

 

 

 

 

 

 

97,182

 

Commercial paper

 

 

 

 

 

 

 

 

65,971

 

 

 

65,971

 

 

 

65,971

 

Corporate bonds

 

 

 

 

 

 

 

 

89,047

 

 

 

89,047

 

 

 

89,047

 

Certificates of deposit

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Subtotal

 

 

97,182

 

 

 

97,182

 

 

 

155,018

 

 

 

155,018

 

 

 

252,200

 

Short-term investments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Agency securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate bonds

 

 

 

 

 

 

 

 

94,792

 

 

 

94,792

 

 

 

94,792

 

Commercial paper

 

 

 

 

 

 

 

 

596,924

 

 

 

596,924

 

 

 

596,924

 

Certificates of deposit

 

 

 

 

 

 

 

 

10,000

 

 

 

10,000

 

 

 

10,000

 

Subtotal

 

 

 

 

 

 

 

 

701,716

 

 

 

701,716

 

 

 

701,716

 

Long-term restricted funds:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Treasury securities

 

 

 

 

 

 

 

 

9,053

 

 

 

9,053

 

 

 

9,053

 

Subtotal

 

 

 

 

 

 

 

 

9,053

 

 

 

9,053

 

 

 

9,053

 

Total

 

$

135,150

 

 

$

135,150

 

 

$

880,770

 

 

$

880,770

 

 

$

1,015,920

 

 

15

 


 

 

 

 

Level 1

 

 

Level 2

 

 

Balance as of

 

 

 

Carrying

Value

 

 

Fair

Value(1)

 

 

Carrying

Value

 

 

Fair

Value(1)

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash

 

$

33,173

 

 

$

33,173

 

 

$

 

 

$

 

 

$

33,173

 

Money market funds

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial paper

 

 

 

 

 

 

 

 

38,420

 

 

 

38,420

 

 

 

38,420

 

Subtotal

 

 

33,173

 

 

 

33,173

 

 

 

38,420

 

 

 

38,420

 

 

 

71,593

 

Restricted cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

 

58,673

 

 

 

58,673

 

 

 

 

 

 

 

 

 

58,673

 

Commercial paper

 

 

 

 

 

 

 

 

188,517

 

 

 

188,517

 

 

 

188,517

 

Corporate bonds

 

 

 

 

 

 

 

 

5,010

 

 

 

5,010

 

 

 

5,010

 

Certificates of deposit

 

 

 

 

 

 

 

 

750

 

 

 

750

 

 

 

750

 

Subtotal

 

 

58,673

 

 

 

58,673

 

 

 

194,277

 

 

 

194,277

 

 

 

252,950

 

Short-term investments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Agency securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate bonds

 

 

 

 

 

 

 

 

487,946

 

 

 

487,946

 

 

 

487,946

 

Commercial paper

 

 

 

 

 

 

 

 

378,048

 

 

 

378,048

 

 

 

378,048

 

Certificates of deposit

 

 

 

 

 

 

 

 

20,000

 

 

 

20,000

 

 

 

20,000

 

Subtotal

 

 

 

 

 

 

 

 

885,994

 

 

 

885,994

 

 

 

885,994

 

Long-term investments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate bonds

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Subtotal

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

91,846

 

 

$

91,846

 

 

$

1,118,691

 

 

$

1,118,691

 

 

$

1,210,537

 

 

(1)

As of March 31, 2016 and December 31, 2015, the Company did not record any OTTI on these assets.

 

 

16

 


 

 

7. Property, Plant, and Equipment

Property, plant, and equipment is stated at cost less accumulated depreciation/amortization and consisted of the following:

 

 

 

 

Estimated

Useful Life

(Years)

 

March 31,

2016

 

 

December 31,

2015

 

 

 

 

 

 

($ in thousands)

 

Oil and Gas Properties:

 

 

 

 

 

 

 

 

 

 

 

Proved properties:

 

 

 

 

 

 

 

 

 

 

 

Well and development costs

 

 

 

 

$

102,410

 

 

$

71,463

 

Less: accumulated depletion

 

 

 

 

 

(2,825

)

 

 

 

 

Total proved properties

 

 

 

 

 

99,585

 

 

 

71,463

 

Unproved properties:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas leasehold

 

 

 

 

 

370,270

 

 

 

382,976

 

Less: accumulated valuation allowance

 

 

 

 

 

(167,489

)

 

 

(175,963

)

 

 

 

 

 

 

202,781

 

 

 

207,013

 

Exploration wells in process

 

 

 

 

 

725,193

 

 

 

615,258

 

Total unproved properties

 

 

 

 

 

927,974

 

 

 

822,271

 

Total oil and gas properties, net

 

 

 

 

 

1,027,559

 

 

 

893,734

 

Other Property and Equipment:

 

 

 

 

 

 

 

 

 

 

 

Computer equipment and software

 

 

3

 

 

8,296

 

 

 

5,350

 

Office equipment and furniture

 

 

 5

 

 

1,349

 

 

 

1,349

 

Leasehold improvements

 

 

 10

 

 

2,150

 

 

 

2,150

 

 

 

 

 

 

 

11,795

 

 

 

8,849

 

Less: accumulated depreciation and amortization

 

 

 

 

 

(6,992

)

 

 

(6,647

)

Total other property and equipment, net

 

 

 

 

 

4,803

 

 

 

2,202

 

Property, plant, and equipment, net

 

 

 

 

$

1,032,362

 

 

$

895,936

 

 

The Company recorded $3.2 million and $0.4 million of depletion, depreciation and amortization expense for the three months ended March 31, 2016 and 2015, respectively.

Proved Oil and Gas Properties

The Heidelberg project was formally sanctioned for development in mid-2013. As a result of the project sanction, the Company reclassified its Heidelberg exploration well costs to proved property well and development costs and these costs will be amortized as the related proved developed reserves are produced. During the quarter ended March 31, 2015, the Company assigned its 9.375% ownership interest in the Heidelberg prospect to its wholly owned subsidiary, Cobalt GOM #1 LLC (“GOM #1”). As a result, the carrying value of the costs capitalized for all the Heidelberg projects as of March 31, 2015 were transferred to GOM #1. GOM #1 was established to secure the Heidelberg assets creating a first priority lien in the Company’s interest in preparation for debt instruments to fund the Heidelberg development project. As of March 31, 2016, prior to recognition of impairment charges, the well and development costs consist of $108.8 million relating to exploration, appraisal and development well costs and $239.8 million for costs associated with field development. As of December 31, 2015, prior to recognition of impairment charges, the well and development costs consisted of $104.0 million relating to well costs for the Heidelberg #1 exploration well, Heidelberg #3 appraisal well, and the Heidelberg #4 and Heidelberg #6 development wells and $221.2 million for costs associated with field development.

17

 


 

 

Unproved Oil and Gas Properties

As of March 31, 2016 and December 31, 2015, the Company has the following unproved property acquisition costs, net of valuation allowance on the consolidated balance sheets:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Individual oil and gas leaseholds with carrying value

   greater than $1 million

 

$

295,268

 

 

$

305,270

 

Individual oil and gas leaseholds with carrying value

   less than $1 million

 

 

75,002

 

 

 

77,706

 

 

 

 

370,270

 

 

 

382,976

 

Accumulated valuation allowance

 

 

(167,489

)

 

 

(175,963

)

Total oil and gas leasehold

 

$

202,781

 

 

$

207,013

 

 

Capitalized Exploration Well Costs

If an exploration well provides evidence as to the existence of sufficient quantities of hydrocarbons to justify evaluation for potential development, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally, deepwater and international locations) depending upon, among other things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned geological and engineering studies, (iii) the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan and (iv) the requirement for government sanctioning in international locations before proceeding with development activities.

The following tables reflect the Company’s net changes in and the cumulative costs of capitalized exploration well costs (excluding any related leasehold costs):

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Beginning of period

 

$

615,258

 

 

$

330,099

 

Additions to capitalized exploration

 

 

 

 

 

 

 

 

Exploration well costs

 

 

99,976

 

 

 

285,118

 

Capitalized interest

 

 

10,211

 

 

 

24,161

 

Reclassifications to wells, facilities, and equipment based

   on determination of proved reserves

 

 

 

 

 

 

Amounts charged to expense(1)

 

 

(252

)

 

 

(24,120

)

End of period

 

$

725,193

 

 

$

615,258

 

 

(1)

The amount of $0.3 million for the three months ended March 31, 2016 and $24.1 million for the year ended December 31, 2015, represents impairment charges on exploration wells drilled in the U.S. Gulf of Mexico which did not encounter commercial hydrocarbons.  

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Cumulative costs:

 

 

 

 

 

 

 

 

Exploration well costs

 

$

676,418

 

 

$

576,694

 

Capitalized interest

 

 

48,775

 

 

 

38,564

 

 

 

$

725,193

 

 

$

615,258

 

Well costs capitalized for a period greater than one year

   after completion of drilling (included in table above)

 

$

357,652

 

 

$

351,753

 

 

18

 


 

 

As of March 31, 2016, capitalized exploration well costs that have been suspended longer than one year are associated with the Company’s Shenandoah, North Platte, Anchor, and Diaman discoveries. These well costs are suspended pending ongoing evaluation including, but not limited to, results of additional appraisal drilling, well-test analysis, additional geological and geophysical data and approval of a development plan. Management believes these discoveries exhibit sufficient indications of hydrocarbons to justify potential development and is actively pursuing efforts to fully assess them. If additional information becomes available that raises substantial doubt as to the economic or operational viability of these discoveries, the associated costs will be expensed at that time. The Heidelberg discovery has been sanctioned for development and the Heidelberg capitalized exploration and appraisal well costs were reclassified to development costs in 2013.  In January 2016, the Company achieved initial production of oil and gas from the Heidelberg field.

 

 

8. Other Assets

As of March 31, 2016 and December 31, 2015, the balance in other assets consisted of the following:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

(in thousands)

 

Debt issue costs(1)

 

$

3,419

 

 

$

3,595

 

Rig costs(2)

 

 

11,840

 

 

 

15,397

 

Other deposits

 

 

500

 

 

 

 

 

 

$

15,759

 

 

$

18,992

 

 

(1)

As of March 31, 2016 and December 31, 2015, the $3.4 million and $3.6 million, respectively, in debt issue costs was related to the issuance of the Borrowing Base Facility Agreement, as described in Note 9. These debt issue costs are amortized over the life of the Facility.

(2)

As of March 31, 2016 and December 31, 2015, the $11.8 million and $15.4 million, respectively, relate to costs associated with the Rowan Reliance drilling rig which is currently drilling in U.S. Gulf of Mexico. These costs are capitalized to the wells over the term of the respective drilling rig contracts.

 

 

9. Long-term Debt

As of March 31, 2016, the Company’s long-term debt consists of the Borrowing Base Facility Agreement (the “Facility Agreement”) entered into on May 29, 2015, the 2.625% convertible senior notes due 2019 issued on December 17, 2012 (the “2.625% Notes”), and the 3.125% convertible senior notes due 2024 issued on May 13, 2014 (the “3.125% Notes”, and, collectively with the 2.625% Notes, the “Notes”), as follows:

Borrowing Base Facility Agreement

On May 29, 2015, Cobalt GOM #1 LLC (“GOM#1”), an indirect, wholly-owned subsidiary of the Company entered into a Borrowing Base Facility Agreement (the “Facility Agreement”) with Société Générale, as administrative agent, and certain other lenders. GOM#1 is the direct owner of the oil and gas leases, wells, production facilities and other assets and agreements associated with the Company’s Heidelberg development. GOM#1 does not own any of the Company’s other oil and gas assets. The Facility Agreement currently provides for a limited recourse $150 million senior secured reserve-based term loan facility, although the Company is in discussions with the lenders under the Facility Agreement related to an amendment to the Facility Agreement and a corresponding material reduction in the borrowing base and facility size.  The Facility Agreement requires the maintenance of a debt to equity ratio of the total investment in the Heidelberg development of no more than 70:30. 

The Company is a party to the Facility Agreement and has limited funding obligations thereunder. Until completion of the Heidelberg development in accordance with the current field development plan and certain other requirements set forth in the Facility Agreement (“Completion”), the Company has guaranteed to fund cost overruns that may be incurred up to an aggregate of $38.7 million. The Company agreed to cash collateralize 50% of its funding obligation in respect of cost overruns by depositing $19.4 million in a collateral account to be established pursuant to the terms of the Facility Agreement. As of March 31, 2016, this amount has not been funded.

19

 


 

 

The amount available for borrowing at any one time under the Facility Agreement is limited to a borrowing base amount determined twice a year using agreed projections by applying the lower of (i) a project life coverage ratio of 1.5:1.0 to the sum of discounted projected net revenues from the Heidelberg field and certain capital expenditures and (ii) a loan life coverage ratio of 1.3:1.0 to the sum of discounted projected net revenues from the Heidelberg field and certain capital expenditures. Interim borrowing base redeterminations can take place between scheduled redetermination dates in limited circumstances specified in the Facility Agreement. Loans made under the Facility Agreement are scheduled to amortize in the manner set forth in the Facility Agreement commencing in July 2018 and will mature on the earlier of (a) May 29, 2020 and (b) the last day of the quarter immediately preceding the first quarter in which the aggregate remaining reserves for the Heidelberg field are projected to be less than 20% of the initial approved reserves. In addition, on or before each redetermination, GOM#1 is required to repay such amount of the loans as is required to reduce the aggregate amount of the loans to the borrowing base amount applicable on the day after such redetermination. After Completion, loans are also subject to mandatory prepayment with 33% of GOM#1’s excess cash flow.

The Facility Agreement and certain related hedging obligations, if any, are secured by a first priority security interest in substantially all of the assets of GOM#1 (which are comprised only of the oil and gas leases, wells, production facilities and other assets associated with the Heidelberg development), including a mortgage on GOM#1’s ownership interest in the Heidelberg field, a pledge of the equity interests of GOM#1 and a pledge of certain intercompany receivables held by the Company. All of GOM#1’s revenues from the Heidelberg development are deposited in collateral accounts established pursuant to the Facility Agreement and applied in accordance with a cash waterfall in the manner specified in the Facility Agreement. GOM#1 is required to maintain a debt service reserve account for the benefit of the lenders under the Facility Agreement, which must remain funded at all times to the level specified in the Facility Agreement.

At GOM#1’s election, interest for borrowings under the Facility Agreement are determined by reference to (a) the London interbank offered rate, or LIBOR, plus an applicable margin of (i) 6.00% per annum prior to Completion and (ii) 4.00% following Completion or (b) a base rate plus an applicable margin of (i) 5.00% prior to Completion and (ii) 3.00% following Completion. Prior to Completion, GOM#1 is also required to pay a commitment fee equal to 40% of the applicable margin payable on the unused commitments under the Facility Agreement. Interest on base rate loans and the commitment fee are generally payable quarterly. Interest on LIBOR loans are generally payable at the end of the applicable interest period but no less frequently than quarterly.

The Facility Agreement contains various covenants that limit, among other things, GOM#1’s ability to incur indebtedness, grant liens on its assets, merge or consolidate with other entities, sell its assets, make loans, acquisitions, capital expenditures and other investments, abandon or decommission the Heidelberg field, modify material agreements relating thereto, enter into commodity hedges and pay dividends and distributions to its parent entities.

The Facility Agreement includes customary events of default for transactions of this type, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid, defaults under project documents that are not replaced, change in control, expropriation, abandonment or decommissioning of the Heidelberg field, material title defects, the failure to pay cost overruns when due and the failure to reach Completion on or before May 29, 2018.

In addition, the Facility Agreement provides that an event of default will occur if (a) the debt to equity ratio exceeds 70:30 or (b) the then current projections show that (i) the project loan life coverage ratio in any calculation period will be 1.5:1.0 or less, (ii) the loan life coverage ratio in any calculation period will be 1.3:1.0 or less or (iii) the debt service coverage ratio in any calculation period will be 1.2:1.0 or less.

If an event of default occurs, the lenders will be able to accelerate the maturity of the Facility Agreement and exercise other rights and remedies.

As of March 31, 2016, the Company has not borrowed any amounts under the Facility Agreement.  The Company recently received an extension from the lenders under the Facility Agreement of the deadline to complete the audit of GOM #1 to May 31, 2016.  The Company is currently in discussions with the lenders under the Facility Agreement related to an amendment to the Facility Agreement and a corresponding material reduction in the borrowing base and facility size.  

20

 


 

 

2.625% Convertible Senior Notes due 2019

On December 17, 2012, the Company issued $1.38 billion aggregate principal amount of the 2.625% Notes. The 2.625% Notes are the Company’s senior unsecured obligations and interest is payable semi-annually in arrears on June 1 and December 1 of each year. The 2.625% Notes will mature on December 1, 2019, unless earlier repurchased or converted in accordance with the terms of the 2.625% Notes. The 2.625% Notes may be converted at the option of the holder at any time prior to 5:00 p.m., New York City time, on the second scheduled trading day immediately preceding the maturity date, in multiples of $1,000 principal amount. The 2.625% Notes are convertible at an initial conversion rate of 28.023 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $35.68 per share for a total of approximately 38.7 million underlying shares. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in the indenture governing the 2.625% Notes, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. Upon conversion, the Company’s conversion obligation may be satisfied, at the Company’s option, in cash, shares of common stock or a combination of cash and shares of common stock.

3.125% Convertible Senior Notes due 2024

On May 13, 2014, the Company issued $1.3 billion aggregate principal amount of the 3.125% Notes. The 3.125% Notes are the Company’s senior unsecured obligations and rank equal in right of payment to the 2.625% Notes. Interest on the 3.125% Notes is payable semi-annually in arrears on May 15 and November 15 of each year. The 3.125% Notes will mature on May 15, 2024, unless earlier repurchased, converted or redeemed in accordance with the terms of the Notes. Prior to November 15, 2023, the 3.125% Notes are convertible only under the following circumstances: (1) during any fiscal quarter commencing after March 31, 2015 (and only during such fiscal quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a 30 consecutive trading-day period ending on, and including, the last trading day of the immediately preceding fiscal quarter exceeds $30.00 on each applicable trading day; (2) during the five business-day period after any five consecutive trading-day period (the “3.125% Notes Measurement Period”) in which the trading price per $1,000 principal amount of notes for each trading day of the 3.125% Notes Measurement Period was less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; (3) if the Company calls all or any portion of the 3.125% Notes for redemption, at any time prior to 5:00 p.m., New York City time, on the second scheduled trading day immediately preceding the related redemption date; or (4) upon the occurrence of specified distributions or the occurrence of specified corporate events. On or after November 15, 2023, the 3.125% Notes may be converted at the option of the holder at any time prior to 5:00 p.m., New York City time, on the second scheduled trading day immediately preceding the stated maturity date, in multiples of $1,000 principal amount. As of March 31, 2016, none of the conditions allowing holders of the 3.125% Notes to convert had been met.

The 3.125% Notes are convertible at an initial conversion rate of 43.3604 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $23.06 per share for a total of approximately 56.4 million underlying shares. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in the indenture governing the 3.125% Notes, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. Upon conversion, the Company’s conversion obligation may be satisfied, at the Company’s option, in cash, shares of common stock or a combination of cash and shares of common stock.

Holders of the Notes who convert their Notes in connection with a “make- whole fundamental change”, as defined in the indenture governing these Notes, may be entitled to a make-whole premium in the form of an increase in the conversion rate. Additionally, in the event of a fundamental change, as defined in the indenture governing the Notes, holders of the Notes may require the Company to repurchase for cash all or a portion of their Notes equal to $1,000 or a multiple of $1,000 at a fundamental change repurchase price equal to 100% of the principal amount of Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date.

Upon the occurrence of an Event of Default, as defined within the indenture governing the Notes, the trustee or the holders of at least 25% in aggregate principal amount of the Notes then outstanding may declare 100% of the principal of, and accrued and unpaid interest on, all the Notes to be due and payable immediately.

In accordance with accounting guidance relating to, “Debt with Conversion and Other Options”, the Company separately accounts for the liability and equity conversion components of the Notes due to the Company’s option to settle the conversion obligation in cash. The fair value of the Notes excluding the conversion feature at the date of issuance was calculated based on the fair value of similar non-convertible debt instruments. The resulting value of the conversion option of

21

 


 

 

the Notes was recognized as a debt discount and recorded as additional paid-in capital on the Company’s consolidated balance sheets. Total debt issue cost on the Notes was allocated to the liability component and to the equity component of the Notes accordingly. The debt discount and the liability component of the debt issue costs are amortized over the term of the Notes. The effective interest rate used to amortize the debt discount and the liability component of the debt issue costs were approximately 8.40% and 8.97% on the 2.625% Notes and the 3.125% Notes, respectively, based on the Company’s estimated non-convertible borrowing rate as of the date the Notes were issued. Since the Company incurred losses for all periods, the impact of the conversion option would be anti-dilutive to the earnings per share and therefore was not included in the calculation.

The carrying amounts of the liability components of the Notes were as follows:

 

 

 

March 31, 2016

 

 

December 31, 2015

 

 

 

Principal

Amount

 

 

Unamortized

discount and debt issuance costs (1)

 

 

Carrying

Amount

 

 

Principal

Amount

 

 

Unamortized

discount and debt issuance costs

 

 

Carrying

Amount

 

 

 

($ in thousands)

 

Carrying amount of liability component

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.625% Notes

 

$

1,380,000

 

 

$

(243,961

)

 

$

1,136,039

 

 

$

1,380,000

 

 

$

(258,565

)

 

$

1,121,435

 

3.125% Notes

 

 

1,300,000

 

 

 

(429,419

)

 

 

870,581

 

 

 

1,300,000

 

 

 

(439,540

)

 

 

860,460

 

Total

 

$

2,680,000

 

 

$

(673,380

)

 

$

2,006,620

 

 

$

2,680,000

 

 

$

(698,105

)

 

$

1,981,895

 

 

(1)

Unamortized discount and debt issuance costs will be amortized over the remaining life of the Notes which is 3.75 years for the 2.625% Notes and 8.25 years for the 3.125% Notes.  See Note 1 related to a change in the classification of unamortized debt issuance costs on the Condensed Consolidated Balance Sheets.

The carrying amounts of the equity components of the Notes were as follows:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Debt discount relating to value of conversion option

 

$

866,340

 

 

$

866,340

 

Debt issue costs

 

 

(20,185

)

 

 

(20,185

)

Total

 

$

846,155

 

 

$

846,155

 

 

Fair Value  The fair value of the Notes was calculated based on the fair value of similar debt instruments since an observable quoted price of the Notes or a similar asset or liability is not readily available (Level 2 inputs). As of March 31, 2016 and December 31, 2015, the fair values of the Notes were as follows:

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

2.625% Notes

 

$

671,025

 

 

$

793,500

 

3.125% Notes

 

 

525,899

 

 

 

640,250

 

Total

 

$

1,196,924

 

 

$

1,433,750

 

 

As of March 31, 2016, the Company had $27.0 million accrued for interest on the Notes and commitment fees associated with the Facility Agreement.

For the three months ended March 31, 2016 and 2015, the interest expense, net of capitalized amount, relating to the Notes and certain costs and commitment fees associated with the Facility Agreement was $15.6 million and $20.0 million, respectively.

As of March 31, 2016 and December 31, 2015, the debt discounts associated with the 2.625% Notes and the 3.125% Notes resulted in the recognition of $225.7 million and $233.6 million of deferred tax liability, respectively.

 

 

22

 


 

 

10. Angola Transaction

On August 22, 2015, Cobalt International Energy Angola Ltd. (“Cobalt Angola”), a wholly-owned subsidiary of the Company, executed a purchase and sale agreement (the “Purchase and Sale Agreement”) with Sonangol for the sale by Cobalt Angola to Sonangol of the entire issued and outstanding share capital of CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold the Company’s 40% working interest in each of Block 20 and Block 21 offshore Angola for aggregate gross consideration of $1.75 billion before Angolan withholding taxes of approximately $19.7 million (to be netted out of the gross consideration to be paid to Cobalt Angola) and certain other U.S. and Angolan taxes, expenses, and contingent liabilities. Sonangol Pesquisa e Produção, S.A., an affiliate of Sonangol, currently holds a 30% working interest in Block 20 and a 60% working interest in Block 21. The Angola Transaction is subject to Angolan government approvals.

The Purchase and Sale Agreement provides for the payment of the net consideration by Sonangol to Cobalt Angola of (i) $250 million within 7 days following the execution of the Purchase and Sale Agreement (the “First Payment”), (ii) approximately $1.28 billion within 15 days following the receipt of the Angolan government approvals (the “Second Payment”), and (iii) $200 million within the earlier of 30 days following the execution of a transfer of operations agreement, which will contain terms and conditions governing the transition of operations on each of Block 20 and Block 21 from the Company to a new operator, or one year from the execution of the Purchase and Sale Agreement (the “Third Payment”). The Purchase and Sale Agreement further provides that within 15 days following the receipt of the Angolan government approvals, Sonangol shall reimburse Cobalt Angola for its share of costs attributable to Block 20 and Block 21 for the period from January 1, 2015 through the date upon which Cobalt Angola receives the Angolan government approvals (the “Reimbursement Amount”). The Company estimates that its share of costs attributable to Block 20 and Block 21 for the period from January 1, 2015 through March 31, 2016 is approximately $494.1 million, which excludes (i) a letter of credit cash collateralized by approximately $82.4 million related to Block 20 that will be released following the earlier of the completion of its minimum work obligations on Block 20 or consummation of the Angola Transaction and (ii) outstanding joint interest and other receivables attributable to Block 20 and Block 21 of approximately $147.5 million. The obligation of Cobalt Angola to transfer the share capital of CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd. to Sonangol and consummate the Angola Transaction is subject to the receipt by Cobalt Angola of the First Payment, the Second Payment and the Reimbursement Amount. On February 29, 2016, the Company relinquished its working interest in Block 9.  If the Angolan government approvals are not received within one year from the execution date of the Purchase and Sale Agreement, the Purchase and Sale Agreement will automatically terminate and any obligations executed by the parties thereto shall be restituted in order to put such parties in their original positions as if no agreement had been executed. As a result, the First Payment has been reported as restricted cash and a liability on the balance sheet.

Pursuant to the Purchase and Sale Agreement, the Company is required to provide certain transition services to Sonangol, which may include continuing to support operations on Block 20 and 21 on a no-profit no-loss basis until Sonangol nominates a new operator or operators of such blocks, despite the fact that the Company may have already transferred the share capital of its subsidiaries holding its working interests in Blocks 20 and 21 to Sonangol.

The Company received the First Payment during the quarterly period ended September 30, 2015. The Angola Transaction is currently pending Angolan government approvals, and the Company therefore has not received the Second Payment, Third Payment or Reimbursement Amount.

Royalty Agreement

On February 13, 2009, the Company entered into a restated overriding royalty agreement (the “Royalty Agreement”) with Whitton Petroleum Services Limited (“Whitton”). Pursuant to the terms of the Royalty Agreement, in consideration for Whitton’s consulting services in connection with Blocks 9, 20 and 21 offshore Angola and the Company’s business and operations in Angola, Whitton is to receive quarterly payments (measured in U.S. Dollars) equal to 2.5% of the market price of the Company’s share of the crude oil produced in such quarter and not used in petroleum operations, less the cost recovery crude oil, assuming the applicable government contract is a production sharing agreement. If the applicable government contract is a risk services agreement and not a production sharing agreement (which is the case with respect to Blocks 9 and 21), pursuant to the Royalty Agreement, the Company has undertaken to agree with Whitton an economic model (the “RSA Economic Model”) containing terms equivalent to those in such risk services agreement and using actual production and costs. The RSA Economic Model has not yet been agreed with Whitton. Should the Company assign all of its interest in such Blocks, Whitton may, depending on the option the Company elects, have the right to receive the market value of its rights and obligations under the Royalty Agreement, based upon the amount in cash a willing transferee of such rights and

23

 


 

 

obligations would pay a willing transferor in an arm’s length transaction. Given potential issues regarding how such market value of Whitton’s rights and obligations under the Royalty Agreement could be calculated, including, without limitation, outstanding issues related to the RSA Economic Model, the amount of any such payment that could be owed to Whitton upon consummation of the Angola Transaction is uncertain, but may be significant. Resolution of any such payment may include an expert determination of such cash value payment.  The Company can make no assurance that any results from an expert determination process will be favorable to it.

Assets and Liabilities Held for Sale

The following table summarizes the assets and liabilities associated with Blocks 9, 20, and 21 offshore Angola.  Although the Company relinquished its working interest in Block 9 on February 29, 2016, the Company continues to have assets and liabilities associated with the entity.

 

 

 

March 31,

2016

 

 

December 31,

2015

 

 

 

($ in thousands)

 

Cash and cash equivalents

 

$

32,455

 

 

$

8,578

 

Joint interest and other receivables

 

 

176,139

 

 

 

156,599

 

Prepaid expenses and other current assets

 

 

5,814

 

 

 

8,216

 

Inventory

 

 

48,273

 

 

 

56,224

 

Short term restricted funds

 

 

82,442

 

 

 

22,538

 

Oil and gas properties

 

 

1,555,285

 

 

 

1,465,299

 

Other property and equipment, net

 

 

10,107

 

 

 

10,107

 

Long term restricted funds

 

 

 

 

 

82,568

 

Other assets

 

 

587

 

 

 

922

 

Total assets of the discontinued operation

 

 

1,911,102

 

 

 

1,811,051

 

Trade and other accounts payable

 

 

(24,389

)

 

 

(6,089

)

Accrued liabilities

 

 

(114,863

)

 

 

(128,259

)

Short term contractual obligations

 

 

(93,164

)

 

 

(115,110

)

Long term contractual obligations

 

 

(1,381

)

 

 

(1,381

)

Other long term liabilities

 

 

 

 

 

 

Total liabilities of the discontinued operation

 

$

(233,797

)

 

$

(250,839

)

 

Results for Blocks 9, 20, and 21 offshore Angola classified within discontinued operations consisted of the following:

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

Seismic and exploration

 

$

7,317

 

 

$

3,702

 

Dry hole expense and impairment

 

 

3,552

 

 

 

 

General and administrative

 

 

9,319

 

 

 

6,519

 

Depreciation and amortization

 

 

 

 

 

930

 

Gain on the release of letters of credit (1)

 

 

(4,375

)

 

 

 

Net loss from discontinued operations

 

$

15,813

 

 

$

11,151

 

 

(1)

Amount represents the gain recognized on the release of the Block 9 letter of credit that was previously written off.

 

 

24

 


 

 

11. Seismic and Exploration Expenses

Seismic and exploration expenses consisted of the following:

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

Seismic costs

 

$

(2,453

)

 

$

11,831

 

Leasehold delay rentals

 

 

1,264

 

 

 

1,391

 

Other exploration expense

 

 

(65

)

 

 

845

 

 

 

$

(1,254

)

 

$

14,067

 

 

 

12. Equity Based Compensation

The Company accounts for stock-based compensation at fair value. The Company grants various types of stock-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model. For restricted stock awards with market conditions, the fair value of the awards is measured using the Monte Carlo pricing model. Restricted stock awards without market conditions are valued using the market price of the Company’s common stock on the grant date. The Company records compensation cost, net of estimated forfeitures, for stock-based compensation awards over the requisite service period except for performance-based awards, which are amortized on a straight-line basis over a weighted average period.

During the three months ended March 31, 2016, the Company granted a total of 571,428 shares of restricted stock, 3,491,352 restricted stock units and 1,129,944 stock options to employees which include 571,428 shares of restricted stock and 1,129,944 stock options with both service and market conditions granted to two senior officers under the terms of their employment agreements. During the three months ended March 31, 2016, the Company granted 28,428 shares of common stock as retainer awards and 29,606 restricted stock units to its non-employee directors.

On February 18, 2016, the Company granted 3,491,352 restricted stock units (“RSUs”) under the Company’s 2015 Long Term Incentive Plan (the “2015 Plan”) to the Company’s employees based on the common stock market price at the time of issuance of $2.44 per share.  The RSU’s will vest in equal installments on each of March 1, 2017, March 1, 2018, and March 1, 2019 by issuance of the Company’s shares of common stock or by cash or by a combination thereof, at the discretion of the Company.  The fair value of the RSU’s on the date of grant was $10.4 million.  The Company accounts for the RSUs as compensation cost and records a corresponding liability based on the fair value of the RSUs at the end of each reporting period.  For the three months ended March 31, 2016 and 2015, the Company recognized $0.3 million and $0.0 million, respectively, in compensation expense relating to the RSU awards.

The Company recorded equity based compensation expense, net of forfeitures, of $7.8 million and $5.8 million for the three months ended March 31, 2016 and 2015, respectively.

On February 20, 2015, the Company issued a total of 1,526,835 share appreciation rights (“SARs”) under the Company’s Long Term Incentive Plan to the Company’s officers, based on the common stock market price at the time of issuance of $8.87 per share. The SARs will vest with respect to one-third (1/3) of the underlying shares on each anniversary of the grant date over the next three years and may be settled, at the Company’s discretion, by issuance of the Company’s shares or by cash or by a combination of the Company’s shares and cash based on the fair market value of the shares on date of exercise. The fair value of a SAR is determined using the Black-Scholes-Merton option-pricing model which at the date of grant was $4.53 per SAR share. The Company accounts for the SAR awards as compensation cost and records a corresponding liability based on the fair value of the SARs at the end of each reporting period. As of March 31, 2016, the fair value of each SAR decreased to $2.74, resulting in a reduction of the fair value of $0.8 million. For the three months ended March 31, 2016 and 2015, the Company recognized $0.3 million and $0.3 million, respectively, in compensation expense relating to the SAR awards.

On April 30, 2015, the Company’s stockholders approved the 2015 Plan. The total number of shares of the Company’s common stock available for issuance under the 2015 Plan is 12,000,000. The 2015 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other stock-based awards. As of

25

 


 

 

March 31, 2016, the Company has awarded 1,851,372 shares under the 2015 Plan, not including the 3,491,352 RSU’s which may be settled in cash at the Company’s election.

 

 

13. Income taxes

We recorded no income tax expense or benefit for the three months ended March 31, 2016. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed, and as a result we continue to maintain a full valuation allowance for our net deferred assets as of March 31, 2016.

As of March 31, 2016, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2015.

 

 

14. Contingencies

The Company is currently, and from time to time may be, subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on the Company’s consolidated financial position, results of operations, or liquidity.

 

15. Other Matters

As previously disclosed, in November 2011 a formal order of investigation was issued by the SEC related to the Company’s operations in Angola. In August 2014, the Company received a Wells Notice from the SEC related to this investigation. In January 2015, the Company received a termination letter from the SEC advising that the SEC’s FCPA investigation has concluded and the Staff does not intend to recommend any enforcement action by the SEC. This letter formally concluded the SEC’s investigation. The Company continues to cooperate with the Department of Justice (“DOJ”) with regard to its ongoing parallel investigation. The Company is unable to predict the outcome of the DOJ’s ongoing investigation or any action that the DOJ may decide to pursue.

On February 19, 2016, the Company initiated a workforce reduction program in response to the Angola Transaction and prolonged commodity price weakness, which has resulted in a reduction of the Company’s capital programs and other operations. The Company expects to recognize the majority of these restructuring costs in the first and second quarters of 2016 and will recognize the remaining costs throughout 2016 until the remaining employee terminations have occurred.

Included in the three months ended March 31, 2016 was $3.1 million of severance costs associated with the Company’s workforce reduction plan.

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion contains forward‑looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward‑looking statements as a result of various factors, including, without limitation, those set forth in “Risk Factors” and “Cautionary Note Regarding Forward‑Looking Statements” and the other matters set forth in this Quarterly Report on Form 10‑Q. The following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10‑Q and in our Annual Report on Form 10‑K for the year ended December 31, 2015.

Overview

We are an independent exploration and production company with operations currently focused in the deepwater U.S. Gulf of Mexico. In January 2016, we achieved initial production of oil and gas from the Heidelberg field. Our exploration efforts in the U.S. Gulf of Mexico have resulted in four oil and gas discoveries including the North Platte, Shenandoah, Anchor, and Heidelberg fields, each of which are in various stages of appraisal and development. We also have a non-operated interest in the Diaba Block offshore Gabon.

26

 


 

 

In August 2015, we executed a purchase and sale agreement with Sociedade Nacional de Combustíveis de Angola—Empresa Pública (“Sonangol”) for the sale of our working interests in Blocks 20 and 21 offshore Angola for aggregate gross consideration of $1.75 billion before certain transaction expenses and other U.S. and Angolan taxes. The completion of this transaction is pending the receipt of Angolan government approvals, which may be delayed or may not be consummated.  If the Angolan government approvals are not received within one year form the execution date of the Purchase and Sale Agreement, the Purchase and Sale Agreement will automatically terminate and any obligations executed by the parties thereto shall be restituted in order to put such parties in their original positions as if no agreement had been executed. We are continuing to work with Sonangol regarding the closing of the transaction, but we cannot make any assurances regarding the timing or occurrence of closing.

First Quarter 2016 Operational Highlights

 

·

We completed additional sidetrack appraisal drilling operations at North Platte, which were successful and encountered approximately 500 feet of net oil pay in what appears to be excellent reservoir quality rock.  The fluid, core and pressure samples taken in the sidetrack well indicate that the rock and reservoir properties are the best that we have encountered in the Inboard Lower Tertiary trend with respect to porosity and permeability. We intend to conduct further appraisal drilling at North Platte in the second half of 2016.  We are the operator of and have a 60% working interest in North Platte.

 

·

We spud the Goodfellow #1 exploration well, which will target Inboard Lower Tertiary horizons. The Goodfellow prospect is a 3-way closure and is located approximately 18 miles southwest of our Shenandoah discovery in the Walker Ridge area. We expect results from the Goodfellow #1 exploration well in the second half of 2016. We are the operator of and own a 72.5% working interest in Goodfellow.

 

·

We spud the Anchor #3 appraisal well, which is designed to test the resource potential of the Anchor field as well as assess reservoir continuity, structure, and oil-water contacts.  We also expect to acquire core, pressure, and fluid samples as we continue to evaluate the Anchor field.  We expect results from Anchor #3 in the second half of 2016.  We own a 20% non-operated working interest in Anchor.

 

·

We spud the Shenandoah #5 appraisal well, which is designed to further test the resource potential and commerciality of the Shenandoah field.  We expect results from Shenandoah #5 in the second half of 2016.  We own a 20% non-operated working interest in Shenandoah.

 

·

We achieved initial production from the Heidelberg field from three producing wells tied back to a moored production handling SPAR.  The first producing well was connected to the Heidelberg facility in January 2016, with the second and third producing wells coming online in February and March 2016, respectively.  Net production from Heidelberg averaged approximately 807 barrels of oil equivalent per day (“boepd”) from the commencement of production through the end of the first quarter, and is currently producing approximately 1,100 boepd on a net basis.  Two additional development wells are expected to be drilled, completed and brought onto production at Heidelberg during 2016.  We own a 9.375% non-operated working interest in Heidelberg.  

 

·

We completed drilling operations on the Zalophus #1 pre-salt exploration well in Block 20 offshore Angola, which resulted in a significant discovery of condensate and gas.  This is our sixth pre-salt discovery offshore Angola and the third discovery on Block 20.  The Petroserv Catarina drilling rig is now completing drilling operations on the Golfinho #1 pre-salt exploration well, which is our final exploration well commitment on Block 20 offshore Angola.  Early analysis of the Golfinho well results indicates potential for another large mound feature with Cameia-like fluid and reservoir properties.  If this analysis proves to be correct, Golfinho will be our seventh pre-salt discovery offshore Angola.  The drilling contract for the Petroserv Catarina drilling rig will expire upon completion of drilling operations on the Golfinho #1 exploration well.  With respect to Block 21 offshore Angola, we completed the Cameia development project transition package that will be transferred to Sonangol upon closing of the Angola transaction.  Until the closing of the Angola transaction, we are operator of and hold a 40% working interest in Block 20 and Block 21 offshore Angola.

 

·

In light of the pending sale of our Angola business to Sonangol and the significant and prolonged downturn in oil and gas prices, we commenced a restructuring of our organization that will result in a company-wide

27

 


 

 

 

personnel reduction of approximately 60%.  In connection with this reorganization, we incurred approximately $3.1 million in severance costs in the first quarter of 2016. 

 

·

On April 15, 2016, the Bureau of Safety and Environmental Enforcement (“BSSE”) published the final BOP and well control rule, which is a comprehensive set of regulations that include requirements for blowout preventer systems, double shear rams, third party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspection intervals, and other reforms related to well design and control, casing, cementing, and subsea containment.  We are continuing to evaluate the final rule, but its implementation may increase our operating costs, delay certain of our drilling operations or render certain drilling operations infeasible or impossible due to the increased requirements.

First Quarter 2016 Financial Highlights

 

·

We recorded a net loss from continuing operations of approximately $30.8 million, a 56% decrease from the first quarter of 2015. Total operating expenses were approximately $18.1 million, a decrease of $34.0 million from the first quarter of 2015. The decrease in operating expenses for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, was primarily attributed to $4.0 million in dry hole expense and impairment reversals during the three months ended March 31, 2016 compared to $19.9 million of charges during the three months ended March 31, 2015, in addition to decreased seismic and exploration expenses.

 

·

Capital and operating expenditures from continuing operations were approximately $136.1 million for the three months ended March 31, 2016.

 

·

As of March 31, 2016, we had approximately $1.0 billion in cash, which includes cash and cash equivalents, investments, restricted cash, and the $250 million we received from Sonangol pursuant to the Purchase and Sale Agreement, which is classified as restricted cash pending the closing of the Angola Transaction. This amount of $1.0 billion excludes cash and restricted cash held within assets held for sale.

Results of Operations

The discussion of the results of operations and the period-to-period comparisons presented below for our consolidated continuing operations analyzes our historical results. The following discussion may not be indicative of future results.

28

 


 

 

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

 

 

 

Three Months Ended March 31,

 

 

 

2016

 

 

2015

 

 

Increase

(Decrease)

 

 

%

 

 

 

($ in thousands)

 

Consolidated Operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas revenue:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

1,611

 

 

$

 

 

$

1,611

 

 

N/A

 

Natural gas sales

 

 

25

 

 

 

 

 

 

25

 

 

N/A

 

Total oil and gas revenue

 

 

1,636

 

 

 

 

 

 

1,636

 

 

N/A

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Seismic and exploration

 

 

(1,254

)

 

 

14,067

 

 

 

(15,321

)

 

 

(109

)%

Dry hole expense and impairment

 

 

(3,977

)

 

 

19,897

 

 

 

(23,874

)

 

 

(120

)%

Lease operating expense

 

 

956

 

 

 

 

 

 

956

 

 

N/A

 

General and administrative

 

 

19,137

 

 

 

17,730

 

 

 

1,407

 

 

 

8

%

Accretion expense

 

 

102

 

 

 

 

 

 

102

 

 

N/A

 

Depreciation and amortization

 

 

3,170

 

 

 

412

 

 

 

2,758

 

 

 

669

%

Total operating costs and expenses

 

 

18,134

 

 

 

52,106

 

 

 

(33,972

)

 

 

(65

)%

Operating income (loss)

 

 

(16,498

)

 

 

(52,106

)

 

 

35,608

 

 

 

65

%

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

 

1,338

 

 

 

1,660

 

 

 

(322

)

 

 

(19

)%

Interest expense

 

 

(15,642

)

 

 

(20,020

)

 

 

4,378

 

 

 

(22

)%

Total other income (expense)

 

 

(14,304

)

 

 

(18,360

)

 

 

4,056

 

 

 

(22

)%

Net income (loss) from continuing operations before

   income tax

 

 

(30,802

)

 

 

(70,466

)

 

 

39,664

 

 

 

(56

)%

Income tax expense (benefit)

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) from continuing operations

 

$

(30,802

)

 

$

(70,466

)

 

$

39,664

 

 

 

(56

)%

 

Consolidated:

Oil and gas revenue.  In January 2016, we achieved initial production of oil and gas from the Heidelberg field in the U.S. Gulf of Mexico.  Oil and gas revenue for the three months ended March 31, 2016 was $1.6 million.  Our net revenue interest share of oil and gas volumes as well as price statistics for the three months ended March 31, 2016 and 2015 were as follows:

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

Heidelberg field net production data and average realized prices

 

 

 

 

 

 

 

 

Oil volume (MBbl)

 

 

55.6

 

 

 

 

Average oil price

 

$

28.96

 

 

$

 

Total oil sales

 

$

1,611

 

 

$

 

 

 

 

 

 

 

 

 

 

Gas volume (MMcf)

 

 

13.3

 

 

 

 

Average natural gas price

 

$

1.87

 

 

$

 

Total natural gas sales

 

$

25

 

 

$

 

 

 

 

 

 

 

 

 

 

Total oil and gas revenue

 

$

1,636

 

 

$

 

 

 

 

 

 

 

 

 

 

 

29

 


 

 

Operating costs and expenses.  Our operating costs and expenses consisted of the following during the three months ended March 31, 2016 and 2015:

Seismic and exploration.  Seismic and exploration costs decreased by $15.3 million during the three months ended March 31, 2016, as compared to the three months ended March 31, 2015. The decrease was primarily attributed to the acquisition of $9.5 million of seismic data acquired on eastern U.S. Gulf of Mexico prospects and offshore Canada and $1.3 million of seismic re-processing in the first quarter of 2015 as compared to no significant purchases or re-processing activity in the first quarter of 2016.

Lease operating expense.  In January 2016, we achieved initial production of oil and gas from the Heidelberg field.  Our lease operating expense for the first quarter of 2016 was $1.0 million, or $16.52 per BOE, primarily attributable to fixed and variable costs of the Heidelberg field and associated transportation costs.

Dry hole expense and impairment.  Dry hole expense and impairment decreased by $23.9 million during the three months ended March 31, 2016, as compared to the three months ended March 31, 2015. The decrease is reflected in the following table:

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

 

Increase

(Decrease)

 

 

 

($ in thousands)

 

Impairment of Unproved Leasehold:

 

 

 

 

 

 

 

 

 

 

 

 

Other leasehold (1)

 

$

1,322

 

 

$

 

 

$

1,322

 

Amortization of leasehold with carrying value under

   $1 million

 

 

2,911

 

 

 

2,597

 

 

 

314

 

Impairment of Proved property:

 

 

 

 

 

 

 

 

 

 

 

 

Heidelberg

 

 

(8,462

)

 

 

 

 

 

(8,462

)

Dry Hole Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Anchor #1 exploration well

 

 

(41

)

 

 

560

 

 

 

(601

)

North Platte #2 appraisal well

 

 

(5

)

 

 

16,905

 

 

 

(16,910

)

Fire Fox #1 exploration well

 

 

(137

)

 

 

 

 

 

(137

)

Yucatan #2 exploration well

 

 

15

 

 

 

(141

)

 

 

156

 

Shenandoah VSP

 

 

 

 

 

247

 

 

 

(247

)

Shenandoah bypass core #3

 

 

 

 

 

(372

)

 

 

372

 

Aegean #1 exploration well

 

 

(522

)

 

 

(19

)

 

 

(503

)

Ligurian #2 exploration well

 

 

432

 

 

 

 

 

 

432

 

Ardennes exploration well

 

 

510

 

 

 

 

 

 

510

 

Other Impairments:

 

 

 

 

 

 

 

 

 

 

 

 

Obsolete inventory

 

 

 

 

 

120

 

 

 

(120

)

 

 

$

(3,977

)

 

$

19,897

 

 

$

(23,874

)

 

(1)

Other leasehold includes certain unproved oil and gas leases for properties in the U.S. Gulf of Mexico with carrying value greater than $1 million that we have no exploration activity planned, based on our three-year exploration plan, during the remaining term of the leases.

 

General and administrative.  General and administrative increased $1.4 million from the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.  The increase was primarily attributable to $3.1 million of severance costs associated with our workforce reduction plan recorded in the first quarter of 2016 offset by a decrease in legal fees of $1.7 million.

Depreciation and amortization.  Depreciation and amortization increased $2.8 million from the three months ended March 31, 2016, as compared to the three months ended March 31, 2015 primarily due to the recording of depletion on our Heidelberg field of $2.8 million in the first quarter of 2016.  

30

 


 

 

Other income (expense).  Other income (expense) decreased by $4.1 million during the three months ended March 31, 2016, as compared to the three months ended March 31, 2015. The decrease was primarily attributable to increased capitalized interest of $8.1 million due to project activity, offset by an increase of $12.5 million in amortization of debt discounts.

Income tax expense/benefit.  No income tax benefit has been reflected since a full valuation allowance has been established against the deferred tax asset that would have been generated as a result of the operating results.

Cash Flows

 

 

 

Three Months Ended

March 31,

 

 

 

2016

 

 

2015

 

 

 

($ in thousands)

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

Operating Activities

 

$

72,817

 

 

$

(86,078

)

Investing Activities

 

 

41,447

 

 

 

209,051

 

Financing Activities

 

 

 

 

 

 

 

Operating activities.  Net cash of $72.8 million provided by and $86.1 million used in operating activities during the three months ended March 31, 2016 and 2015, respectively, were primarily related to cash payments for seismic and exploration expenses incurred in the U.S. Gulf of Mexico made in the first quarter of 2015 and a favorable working capital change in the first quarter of 2016.

Investing activities.  Net cash provided by investing activities for the three months ended March 31, 2016 was $41.4 million compared to net cash provided by investing activities of $209.1 million for the three months ended March 31, 2015. The net cash used in investing activities for the three months ended March 31, 2016 was primarily related to net maturities in investment securities offset by expenditures related to drilling of exploration wells.

Financing activities.  We had no material financing activities during the three months ended March 31, 2016 and 2015.

 

Liquidity and Capital Resources

As of March 31, 2016, we had approximately $1.0 billion in cash, which includes cash and cash equivalents, investments, restricted cash, and the $250 million we received from Sonangol pursuant to the Purchase and Sale Agreement, which is classified as restricted cash pending the closing of the Angola Transaction. This amount of $1.0 billion excludes cash and restricted cash held within assets held for sale. Although we increased our working interest in the Goodfellow prospect during the first quarter of 2016, we continue to expect to expend approximately $450 to $500 million for our U.S. Gulf of Mexico capital expenditures in 2016, which excludes general and administrative and interest expense, but assumes additional anticipated cost reductions are realized.  We expect that our total cash outlays will be between $600 to $650 million for continuing operations in the U.S. Gulf of Mexico in 2016.  In addition, we expect to spend approximately $120 million on a net basis for operations on Blocks 20 and 21 Angola pending the closing of the Angola Transaction. Pursuant to the terms of the Purchase and Sale Agreement governing the Angola Transaction, we are entitled to reimbursement of such amounts upon the closing of the Angola Transaction. We expect that our existing cash on hand plus proceeds from the closing of the Angola Transaction will be sufficient to fund our current operations for the foreseeable future; however, we are evaluating future sources of capital in the event that the Angola Transaction does not close or is further delayed.

On May 29, 2015, Cobalt GOM #1 LLC, our indirect, wholly-owned subsidiary, entered into a Borrowing Base Facility Agreement (the “Facility Agreement”) with Société Générale, as administrative agent, and certain other lenders. The Facility Agreement provides for a limited recourse senior secured reserve-based term loan facility with a current borrowing base of $150 million. We are currently in discussions with the lenders under the Facility Agreement related to an amendment to the Facility Agreement and a corresponding material reduction in the borrowing base and facility size.  

Although we commenced initial production from our Heidelberg project in January 2016, our capital and operating expenditures will vastly exceed the revenue we expect to receive from our oil and gas operations for the foreseeable future. Until substantial production is achieved, our primary sources of liquidity are expected to be cash on hand, the proceeds from

31

 


 

 

the closing of the Angola Transaction, any funds that may be available to us under the Facility Agreement, proceeds from any future reserve-based lending arrangements, equity and debt financings, and asset-based ventures and asset monetizations.

We expect to incur substantial expenditures and generate significant operating losses as we:

 

·

progress our North Platte, Shenandoah and Anchor discoveries toward project sanction;

 

·

continue development drilling activities on the Heidelberg field with the aim to increase its oil and gas production over time;

 

·

selectively conduct exploration drilling on our current U.S. Gulf of Mexico acreage;

 

·

pursue new acreage opportunities in the U.S. Gulf of Mexico; and

 

·

incur expenses related to operating as a public company and compliance with regulatory requirements.

Our future financial condition and liquidity will be impacted by, among other factors, the timing or occurrence of the closing of the Angola Transaction, the production rates achieved from our Heidelberg project, our ability to obtain financing or refinance existing indebtedness, oil and gas prices, the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed with which we can bring such discoveries to production, whether and to what extent we invest in additional oil leases and concessional licenses, and the actual cost of exploration, appraisal and development of our prospects. We may also seek additional funding through equity and debt financings. Additional funding may not be available to us on acceptable terms or at all. In addition, the terms of any financing may adversely affect the holdings or the rights of our existing stockholders. For example, if we raise additional funds by issuing additional equity securities, further dilution to our existing stockholders will result. Funds available to us under existing or future reserve-based lending arrangements, including the Facility Agreement, may decrease in connection with periodic redeterminations of the value of the oil and gas reserves pledged pursuant to such lending arrangements. If we are unable to obtain or maintain funding on a timely basis or on acceptable terms, we may be required to significantly curtail our exploration, appraisal and development activities.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our 2015 Annual Report on Form 10-K for the year ended December 31, 2015. Also refer to the Notes to the Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Report.

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Other than as discussed below, there have been no material changes in market risk from the information provided under Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2015 Annual Report on Form 10-K for the year ended December 31, 2015.

Commodity Price Risk

Our revenues, net income, cash flows, capital expenditures and rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile, with oil and gas prices recently declining significantly.  Our oil sales are indexed against West Texas Intermediate crude.  Oil prices in 2015 ranged between $61.43 and $34.73 during the year.  In June 2014, West Texas Intermediate crude peaked above $107.26 per barrel and as recently as January 2016, had fallen below $30 per barrel.

Item 4.

Controls and Procedures

We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Securities Exchange Act of 1934, as amended (the “Exchange Act”), Rules 13a-15 and 15d-15 as of the end of the period covered by this Report. Based on that evaluation, our Chief Executive Officer and our Chief Financial

32

 


 

 

Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

33

 


 

 

PART II—OTHER INFORMATION

Item 1.

Legal Proceedings

There have been no material changes in the information provided under Part I, Item 3. “Legal Proceedings” in our 2015 Annual Report on Form 10-K for the year ended December 31, 2015.

Item 1A.

Risk Factors

There have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

 

 

34

 


 

 

Item 6.

Exhibits 

 

Exhibit
Number

 

Description of Document

31.1*

 

Certification of the Chief Executive Officer pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934

31.2*

 

Certification of the Chief Financial Officer pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934

32.1**

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

32.2**

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

101.INS*

 

XBRL Instance Document

101.SCH*

 

XBRL Schema Document

101.CAL*

 

XBRL Calculation Linkbase Document

101.DEF*

 

XBRL Definition Linkbase Document

101.LAB*

 

XBRL Labels Linkbase Document

101.PRE*

 

XBRL Presentation Linkbase Document

 

*

Filed herewith.

**

Furnished herewith.

35

 


 

 

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.

 

 

Cobalt International Energy, Inc.

 

 

 

 

 

 

 

By:

/s/ Joseph H. Bryant

 

 

Name:

Joseph H. Bryant

 

 

Title:

Chairman of the Board of Directors and Chief Executive Officer

 

 

 

 

 

 

 

By:

/s/ Shannon E. Young, III

 

 

Name:

Shannon E. Young, III

 

 

Title:

Executive Vice President and Chief Financial Officer

 

Dated: May 3, 2016

36

 


 

 

EXHIBIT INDEX

Exhibit
Number

 

Description of Document

31.1*

 

Certification of the Chief Executive Officer pursuant to Rule 13a‑ 14(a)/15d‑14(a) of the Securities Exchange Act of 1934

31.2*

 

Certification of the Chief Financial Officer pursuant to Rule 13a‑ 14(a)/15d‑14(a) of the Securities Exchange Act of 1934

32.1**

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

32.2**

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

101.INS*

 

XBRL Instance Document

101.SCH*

 

XBRL Schema Document

101.CAL*

 

XBRL Calculation Linkbase Document

101.DEF*

 

XBRL Definition Linkbase Document

101.LAB*

 

XBRL Labels Linkbase Document

101.PRE*

 

XBRL Presentation Linkbase Document

 

*

Filed herewith.

**

Furnished herewith.

 

37