UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

For the quarterly period ended June 30, 2016

or

For the transition period from            to           

Commission file number: 001‑34579

Cobalt International Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

(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.

 

 

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 June 30, 2016: 414,154,631 shares.

 

 

 

 

 

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TABLE OF CONTENTS

 

 

 

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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:

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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.

 

 

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PART I—FINANCIAL INFORMATION

COBALT INTERNATIONAL ENERGY, INC.

 

 

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Cobalt International Energy, Inc.

Condensed Consolidated Balance Sheets

 

 

See accompanying notes.

 

 

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Cobalt International Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

 

 

See accompanying notes.

 

 

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Cobalt International Energy, Inc.

Condensed Consolidated Statements of Changes in Stockholders’ Equity

(Unaudited)

 

 

See accompanying notes.

 

 

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Cobalt International Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

 

See accompanying notes.

 

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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”).  On July 26, 2016, the Company’s Chief Executive Officer met with Sonangol’s Chairwoman of the Board of Directors Isabel dos Santos and members of her executive team in Luanda, Angola to discuss the status of the Angolan Transaction.  At this meeting, it was jointly agreed with Sonangol that the Company would market its working interests in Blocks 20 and 21 for sale by the Company to a third party other than Sonangol.  On August 1, 2016, the Company received a letter from Chairwoman Isabel dos Santos confirming Sonangol’s support of such marketing and sale process. The Company therefore believes that it is unlikely that the Angola Transaction will close pursuant to the terms of the Purchase and Sale Agreement and believe that it is likely that the Purchase and Sale Agreement will automatically terminate on August 22, 2016.  In such a case, the Purchase and Sale Agreement provides that the parties are to be restituted in order to put them in their original positions as if no agreement had been executed. The Company plans to work with Sonangol to understand and agree on the financial and operational implications of this provision. With respect to the marketing of its Angolan assets, the Company intends to immediately commence the marketing and sale process.  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 six months ended June 30, 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.

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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 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 May 2016, the FASB issued Accounting Standards Update No. 2016-11 (“ASU 2016-11”), Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815):  Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting.  The guidance requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standards in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of these ASUs, and has not determined the impact these standards may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.

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.

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.

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,

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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 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 June 30, 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 June 30, 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.

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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.  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 six months ended June 30, 2016:

 

 

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 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 weighted average number of shares used in the calculation for the three and six months ended June 30, 2016 were 409,920,869 and 409,590,679, respectively. The calculation of diluted 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 and six months ended June 30, 2016, 8,808,708 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 loss per share calculation because they were anti-dilutive. For the three and six months ended June 30, 2015, 9,967,516 shares of non-vested restricted 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 loss per share because they are anti-dilutive.

 

 

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2. Cash and Cash Equivalents

Cash and cash equivalents consisted of the following:

 

 

 

 

3. Restricted Cash and Cash Equivalents and Investments

Restricted cash and cash equivalents and investments consisted of the following:

 

 

 

 

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 June 30, 2016 and December 31, 2015, the balance in joint interest, revenue, and other receivables consisted of the following:

 

 

 

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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 June 30, 2016 and December 31, 2015:

 

 

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

 

 

The contractual maturities of these held-to-maturity securities as of June 30, 2016 and December 31, 2015 were as follows:

 

 

 

6. Fair Value Measurements

The fair values of the Company’s cash and cash equivalents, joint interest and other receivables, short-term and long-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.  The Company secures valuations from its brokers to price U.S. Treasury bills, U.S. Treasury notes, commercial paper, U.S. agency securities, and corporate bonds.  All of the Company’s brokers and custodians use Interactive Data Corporation as a third party pricing service to price corporate bonds, U.S. Treasury bills, U.S. Treasury notes, and U.S. agency securities, and S&P to price commercial paper.

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.

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

 

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7. Property, Plant, and Equipment

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

 

 

The Company recorded $4.2 million and $0.4 million of depletion, depreciation and amortization expense for the three months ended June 30, 2016 and 2015, respectively, and $7.5 million and $0.8 million for the six months ended June 30, 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 depleted 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. As of June 30, 2016, prior to recognition of impairment charges, the well and development costs consisted of $102.4 million relating to exploration, appraisal and development well costs and $219.9 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.

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Unproved Oil and Gas Properties

As of June 30, 2016 and December 31, 2015, the Company has the following unproved property acquisition costs, net of valuation allowance on the consolidated balance sheets:

 

 

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):

 

 

 

 

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As of June 30, 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 June 30, 2016 and December 31, 2015, the balance in other assets consisted of the following:

 

 

 

 

9. Long-term Debt

As of June 30, 2016, the Company’s long-term debt consists of 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 June 17, 2016, Cobalt GOM #1 LLC (“GOM #1”), an indirect wholly-owned subsidiary of the Company, terminated the Borrowing Base Facility Agreement among GOM #1, the Company, Société Générale, as administrative agent, and certain other lenders named therein (the “Facility Agreement”). The Facility Agreement provided for a limited recourse $150 million senior secured reserve-based term loan facility, with an amount available for borrowing at any one time limited to a periodically adjusted borrowing base amount. Based on discussions between the Company and the lenders under the Facility Agreement, the borrowing base amount under the Facility Agreement was expected to be materially reduced to a level that would not justify the ongoing expense of maintaining the facility. No borrowings were outstanding under the Facility Agreement at the time of termination, and no prepayment fees were payable by the Company or GOM #1 upon termination. Following termination of the Facility Agreement, all liens, mortgages, pledges and other security provided in favor of the lenders in connection with the Facility Agreement were terminated and released.  In June 2016, the Company wrote off $3.3 million in debt issuance costs associated with the Facility Agreement.

 

 

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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 June 30, 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 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

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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:

 

 

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

 

 

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 June 30, 2016 and December 31, 2015, the fair values of the Notes were as follows:

 

 

As of June 30, 2016, the Company had $7.8 million accrued for interest on the Notes.

For the three months ended June 30, 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 $16.0 million and $17.8 million, respectively. For the six months ended June 30, 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 $31.6 million and $37.9 million, respectively.

As of June 30, 2016 and December 31, 2015, the debt discounts associated with the 2.625% Notes and the 3.125% Notes resulted in the recognition of $217.5 million and $233.6 million of deferred tax liability, respectively.

 

 

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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 (the “Angola Transaction”). In accordance with the Purchase and Sale Agreement, Sonangol paid the Company $250 million (the “First Payment”).  The First Payment has been reported as restricted cash and a liability on the balance sheet. 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.

On July 26, 2016, the Company’s Chief Executive Officer met with Sonangol’s Chairwoman of the Board of Directors Isabel dos Santos and members of her executive team in Luanda, Angola to discuss the status of the Angolan Transaction.  At this meeting, it was jointly agreed with Sonangol that the Company would market its working interests in Blocks 20 and 21 for sale by the Company to a third party other than Sonangol.  On August 1, 2016, the Company received a letter from Chairwoman Isabel dos Santos confirming Sonangol’s support of such marketing and sale process.  The Company therefore believes that it is unlikely that the Angola Transaction will close pursuant to the terms of the Purchase and Sale Agreement and believe that it is likely that the Purchase and Sale Agreement will automatically terminate on August 22, 2016.  In such a case, the Purchase and Sale Agreement provides that the parties are to be restituted in order to put them in their original positions as if no agreement had been executed. The Company plans to work with Sonangol to understand and agree on the financial and operational implications of this provision including with respect to the return of the First Payment and the payment of the $158.6 million of receivables owed to the Company by Sonangol.  With respect to the marketing of its Angolan assets, the Company intends to immediately commence the marketing and sale process.  

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.  The Company continues to assess the balances for possible impairment as the  assets and liabilities held for sale are required to be presented at fair value.  There has been no impairment identified to date.

 

 

 

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

 

 

 

 

11. Seismic and Exploration Expenses

Seismic and exploration expenses consisted of the following:

 

 

 

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 six months ended June 30, 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 six months ended June 30, 2016, the Company granted 82,898 shares of common stock as retainer awards and 362,934 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 June 30, 2016 and 2015, the Company recognized $1.3 million and $0.0 million, respectively, in compensation expense relating to the RSU awards. For the six months ended June 30, 2016 and 2015, the Company recognized $1.3 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 ($4.9) million and $7.1 million for the three months ended June 30, 2016 and 2015, respectively. The Company recorded equity based compensation expense, net of forfeitures, of $2.8 million and $13.0 million for the six months ended June 30, 2016 and 2015, respectively.

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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 June 30, 2016, the fair value of each SAR decreased to $2.74, resulting in a reduction of the fair value of $1.3 million. For the three months ended June 30, 2016 and 2015, the Company recognized $0.1 million and $0.4 million, respectively, in compensation expense relating to the SAR awards. For the six months ended June 30, 2016 and 2015, the Company recognized $0.6 million and $0.9 million, respectively, in compensation expense relating to the SAR.

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 June 30, 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 and six months ended June 30, 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 June 30, 2016.

As of June 30, 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 and six months ended June 30, 2016 was $3.0 million and $6.1 million, respectively, of severance costs associated with the Company’s workforce reduction plan.

 

 

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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.

In August 2015, we executed a purchase and sale agreement (the “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 “Angolan Transaction”). On July 26, 2016, our Chief Executive Officer met with Sonangol’s Chairwoman of the Board of Directors Isabel dos Santos and members of her executive team in Luanda, Angola to discuss the status of the Angolan Transaction.  At this meeting, it was jointly agreed with Sonangol that we would market our working interests in Blocks 20 and 21 for sale by us to a third party other than Sonangol.  On August 1, 2016, we received a letter from Chairwoman Isabel dos Santos confirming Sonangol’s support of such marketing and sale process.  We therefore believe that it is unlikely that the Angola Transaction will close pursuant to the terms of the Purchase and Sale Agreement and believe that it is likely that the Purchase and Sale Agreement will automatically terminate on August 22, 2016.  In such a case, the Purchase and Sale Agreement provides that the parties are to be restituted in order to put them in their original positions as if no agreement had been executed. We plan to work with Sonangol to understand and agree on the financial and operational implications of this provision. With respect to the marketing of our Angolan assets, we intend to immediately commence the marketing and sale process.

Second Quarter 2016 Operational Highlights

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Second Quarter 2016 Financial Highlights

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.

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Three Months Ended June 30, 2016 Compared to the Three Months Ended June 30, 2015

 

 

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 June 30, 2016 was $3.2 million.  Our net revenue interest share of oil and gas volumes as well as price statistics for the three months ended June 30, 2016 and 2015 were as follows:

 

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Operating costs and expenses.  Our operating costs and expenses consisted of the following during the three months ended June 30, 2016 and 2015:

Seismic and exploration.  Seismic and exploration costs decreased by $4.9 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015. The decrease was primarily attributed to the acquisition of $7.1 million of seismic data acquired on eastern U.S. Gulf of Mexico prospects, offshore Canada, and Gabon, and $1.3 million of seismic re-processing in the second quarter of 2015 as compared to a $3.0 million purchase of seismic data acquired for the U.S Gulf of Mexico in the second quarter of 2016 as well as a $0.5 million decrease in other exploration expenses primarily due to decreased inventory storage and refurbishing costs attributable to lower inventory levels in 2016 compared to 2015.

Dry hole expense and impairment.  Dry hole expense and impairment increased by $150.0 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015. The increase is reflected in the following table:

 

 

Lease operating expense.  In January 2016, we achieved initial production of oil and gas from the Heidelberg field.  Our lease operating expense for the second quarter of 2016 was $1.7 million, or $18.71 per BOE, primarily attributable to fixed and variable costs of the Heidelberg field and associated transportation costs.

General and administrative.  General and administrative decreased $1.3 million from the three months ended June 30, 2016 as compared to the three months ended June 30, 2015.  The decrease was primarily attributable to an $11.3 million reversal of expense related to forfeitures of unvested equity awards associated with our workforce reduction plan offset by an increase in payroll of $3.0 million related to severance costs.  The decrease was further offset by a $6.5 million reduction in recoveries from our partners due to less activity and $0.5 million in reduced office expenses.   

Depreciation and amortization.  Depreciation and amortization increased $3.9 million from the three months ended June 30, 2016, as compared to the three months ended June 30, 2015 primarily due to the recording of depletion on our Heidelberg field of $3.7 million in the second quarter of 2016.  

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Other income (expense).  Other expense increased by $0.8 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015. The increase was primarily due to a gain on the sale of asset recorded in the second quarter of 2015 with no such activity in 2016 offset by decreased interest expense.  The decrease in interest expense was due to increased interest capitalization of $7.5 million due to project activity offset by increased amortization of debt discount of $1.6 million and the write off of $3.3 million in debt issuance costs associated with the Facility agreement.

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.

Six Months Ended June 30, 2016 Compared to the Six Months Ended June 30, 2015

 

 

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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 six months ended June 30, 2016 was $4.8 million.  Our net revenue interest share of oil and gas volumes as well as price statistics for the six months ended June 30, 2016 and 2015 were as follows:

 

 

Operating costs and expenses.  Our operating costs and expenses consisted of the following during the six months ended June 30, 2016 and 2015:

Seismic and exploration.  Seismic and exploration costs decreased by $20.3 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015. The decrease was primarily attributed to the acquisition of $11.6 million of seismic data acquired on eastern U.S. Gulf of Mexico prospects, offshore Canada, and Gabon, and $7.5 million of seismic re-processing and other geological charges in the 2015 as well as a $1.2 million decrease in other exploration expenses primarily due to decreased inventory storage and refurbishing costs attributable to lower inventory levels in 2016 compared to 2015.

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Dry hole expense and impairment.  Dry hole expense and impairment increased by $126.1 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015. The increase is reflected in the following table:

 

 

Lease operating expense.  In January 2016, we achieved initial production of oil and gas from the Heidelberg field.  Our lease operating expense for the second quarter of 2016 was $2.7 million, or $17.86 per BOE, primarily attributable to fixed and variable costs of the Heidelberg field and associated transportation costs.

General and administrative.  General and administrative increased $0.1 million from the six months ended June 30, 2016 as compared to the six months ended June 30, 2015.  The increase was primarily attributable to an increase in severance costs of $6.1 million and a $2.8 million increase in consulting fees offset by a $7.1 reduction in partner recoveries due to less activity and a decrease in staff and other office costs of $1.7 million.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization increased $6.7 million from the six months ended June 30, 2016, as compared to the six months ended June 30, 2015 primarily due to the recording of depletion on our Heidelberg field of $6.6 million in the first six months of 2016.  

Other income (expense).  Other expense decreased by $3.3 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015. The decrease was primarily due to decreased interest expense offset by a gain on the sale of asset recorded in the second quarter of 2015 with no such activity in 2016.  The decrease in interest expense was due to increased interest capitalization of $15.5 million due to project activity offset by increased amortization of debt discount of $4.5 million and the write off of $3.3 million in debt issuance costs associated with the Facility agreement.

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.

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Cash Flows

 

 

Operating activities.  Net cash of $1.6 million provided by and $122.3 million used in operating activities during the six months ended June 30, 2016 and 2015, respectively, were primarily related to cash payments for general and administrative expenses and seismic and exploration expenses incurred in the U.S. Gulf of Mexico made in the first half of 2015 and a favorable working capital change in the first half of 2016.

Investing activities.  Net cash provided by investing activities for the six months ended June 30, 2016 was $269.5 million compared to net cash provided by investing activities of $210.7 million for the six months ended June 30, 2015. The net cash used in investing activities for the six months ended June 30, 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 six months ended June 30, 2016.  For the six months ended June 30, 2015, net cash used in financing activities of $4.0 million was related to debt issuance costs associated with the Facility Agreement entered into on May 29, 2015.

 

Liquidity and Capital Resources

As of June 30, 2016, we had approximately $833.8 million 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. This amount of $833.8 million excludes $43.5 million in cash and restricted cash held within assets held for sale as of June 30, 2016. We expect to expend approximately $500 to $550 million for our U.S. Gulf of Mexico capital expenditures in 2016, which excludes general and administrative and interest expense.  We expect that our total cash outlays will be between $650 to $700 million for continuing operations in the U.S. Gulf of Mexico in 2016, of which $290.3 million has been spent as of June 30, 2016.  In addition, we expect to spend approximately $138 million on a net basis for operations on Blocks 20 and 21 Angola in 2016, of which $118.6 million has been spent as of June 30, 2016. If we are unable to raise additional sources of capital, we expect our cash position at December 31, 2016 will be between $350 to $400 million, subject to additional working capital adjustments.  This assumes that the Angola Transaction does not close and we repay the $250 million initial payment we received from Sonangol, plus the $26 million of cash calls and the letter of credit on Block 9, net of approximately $158.6 million in receivables currently owed by Sonangol to us.

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 the sale of our Angola assets, if any, proceeds from any future equity and debt financings, and asset monetizations.

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

Our future financial condition and liquidity will be impacted by, among other factors, the timing or occurrence of the sale of our Angola assets, if any, our ability to sell additional assets, our ability to obtain financing or refinance existing indebtedness, the production rates achieved from our Heidelberg project, oil and gas prices, the number of commercially

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viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed and cost 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.

In order to develop our U.S. Gulf of Mexico discoveries into producing oil and gas properties, we will need to raise substantial additional capital, which may include equity and debt financings and sales of additional assets.  Such 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.  If we are unable to sell our Angola assets on acceptable terms, or at all, our funding needs will become more acute.  If we are unable to raise substantial additional 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.

 

 

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.

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 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 June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II—OTHER INFORMATION

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, other than the following:

On May 6, 2016, Gaines, a purported stockholder, filed a derivative action in the 295th District Court in Harris County, Texas against us, as a nominal defendant, certain of our current and former officers and directors, and certain investment firms and funds.  The lawsuit alleges that current and former officers and directors breached their fiduciary duties by making, and permitting us to make, alleged misrepresentations about two of our exploration wells offshore Angola; that certain officers received performance-based compensation in excess of what they were entitled; and that the investment firms and funds owed a fiduciary duty to us as controlling stockholders and breached that duty by engaging in insider trading.  The lawsuit further alleges that demand was wrongfully refused.  The plaintiff asserts claims for breach of fiduciary duty and unjust enrichment and seeks damages in an unspecified amount, disgorgement of profits, appropriate equitable relief, and an award of attorney fees and other costs and expenses.  The Company filed its answer and special exceptions challenging the plaintiff’s standing to bring such claims against the Company on July 8, 2016.  The matter remains ongoing.

On May 13, 2016, we filed suit against XL Specialty Insurance Company (“XL”) in Harris County District Court in Houston, Texas. We assert XL improperly denied coverage for insurance claims made on July 30, 2012 and other claims subsequently submitted to them in connection with our defending against the St. Lucie lawsuit, the Ogden derivative action, and other investigations and actions. We allege breach of contract and seek a declaratory judgment that XL is obligated to pay any additional loss suffered by us due to the circumstances, investigation, and claims described in the suit. Discovery is ongoing in the case and trial is set for June 2017.

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, other than the following:

If the Angola Transaction does not close or we are unable to sell our Angola assets on acceptable terms to another third party, our liquidity will be materially adversely impacted.

In August 2015, we executed the Purchase and Sale Agreement with Sonangol for the sale of our working interests in Blocks 20 and 21 offshore Angola in connection with the Angola Transaction. On July 26, 2016, our Chief Executive Officer met with Sonangol’s Chairwoman of the Board of Directors Isabel dos Santos and members of her executive team in Luanda, Angola to discuss the status of the Angolan Transaction.  At this meeting, it was jointly agreed with Sonangol that we would market our working interests in Blocks 20 and 21 for sale by us to a third party other than Sonangol.  On August 1, 2016, we received a letter from Chairwoman Isabel dos Santos confirming Sonangol’s support of such marketing and sale process.  We therefore believe that it is unlikely that the Angola Transaction will close pursuant to the terms of the Purchase and Sale Agreement and believe that it is likely that the Purchase and Sale Agreement will automatically terminate on August 22, 2016.  In such a case, the Purchase and Sale Agreement provides that the parties are to be restituted in order to put them in their original positions as if no agreement had been executed. We plan to work with Sonangol to understand and agree on the financial and operational implications of this provision, including with respect to development schedules and other timelines.  There can be no assurance that we will be able to do so and such failure could materially adversely affect the value of our licenses and our ability to sell them. The inability to close the Angola Transaction or sell our Angola assets to another third party on acceptable terms, or at all, or the repayment of the initial payment of $250 million to Sonangol, would each have a material adverse impact on our liquidity position.

As previously disclosed, 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 and Whitton will likely need to agree upon an economic model containing terms equivalent to those in such risk services agreement and using actual production and costs. Should the Company assign all of its interest in such Blocks to a third party, Whitton may, depending on the option

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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 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, the amount of any such payment that could be owed to Whitton upon consummation of any sale of the Company’s working interests in Block 20 and 21 is uncertain, but may be significant.

In July 2016, the Bureau of Ocean Energy Management (“BOEM”) announced updated financial assurance and risk management requirements of offshore leases, which may increase our cost of operations or have a material adverse effect on our liquidity and impair our ability to operate in the U.S. Gulf of Mexico.

On July 14, 2016, the BOEM announced updated financial assurance and risk management requirements for offshore leases.  The Notice to Lessees No. 2016-N01 (“NTL”) details procedures to determine a lessee’s ability to carry out its lease obligations – primarily the decommissioning of Outer Continental Shelf (OCS) facilities – and whether to require lessees to furnish additional financial assurance.  The NTL provides updated criteria for determining a lessee’s ability to self-insure its OCS liabilities based upon the lessee’s financial capacity and financial strength.  It also provides new methods and additional flexibility for lessees to meet their additional financial security requirements through a tailored plan.  The BOEM has stated that it will focus first on those properties for which there is only one leaseholder responsible for decommissioning.  Those leaseholders will have 60 days from the date of an order requiring additional financial security to comply.  For all other holdings, leaseholders will have 120 days from the date they receive an order to provide additional security, if required.  Alternatively, lessees can provide a tailored financial plan to BOEM, which will permit the use of forms of financial security other than surety bonds and pledges of treasury securities and allow companies to phase in funding of the additional security.  We are continuing to review the NTL and guidance provided by the BOEM to assess its impact on our operations in the U.S. Gulf of Mexico, although it is possible we may receive an order from BOEM in the future to post additional financial security, which may not be available on acceptable terms, or at all.  The NTL and any BOEM order to post additional financial security may increase our cost of operations or have a material adverse effect on our liquidity and impair our ability to operate in the U.S. Gulf of Mexico.

On May 26, 2016, we withheld an aggregate amount of 53,003 shares of our common stock, at a price of $2.60 per share, to satisfy minimum tax withholding obligations of certain of our former employees in connection with the lapse of restrictions on restricted stock.

On June 30, 2016, we withheld an aggregate amount of 46,247 shares of our common stock, at a price of $1.37 per share, to satisfy minimum tax withholding obligations of an employee in connection with the lapse of restrictions on restricted stock.

 

 

Not applicable.

Not applicable.

Adoption of the Executive Severance and Change in Control Benefit Plan

Effective as of July 28, 2016 (the “Effective Date”), the Board of Directors (the “Committee”) of Cobalt International Energy, Inc. (the “Company”) adopted and approved the Cobalt International Energy, Inc. Executive Severance and Change in Control Benefit Plan (the “Plan”).  The Plan provides benefits to eligible executives of the Company designated by the Committee (including certain of the named executive officers, including the Company’s Chief Financial Officer) in the event of a termination of employment under certain circumstances.  Unless and until the Compensation Committee of the Board of Directors approves otherwise, Timothy J. Cutt, the Company’s Chief Executive Officer, James W. Farnsworth, the Company’s Chief Exploration Officer and Executive Vice President, and James H. Painter, the Company’s Executive Vice

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President and Interim Chief Operating Officer, will not be eligible to participate in the Plan or otherwise receive any payments, benefits or other consideration under the Plan.  The following is a brief description of the Plan.  The description does not purport to be complete and is qualified in its entirety by reference to the full text of the Plan, which is attached hereto as Exhibit 10.1 and incorporated herein by reference.

Upon a “qualifying termination” (as defined in the Plan), Plan participants who are named executive officers will be eligible to receive the following benefits:

If a Plan participant who is a named executive officer experiences a qualifying termination within two years following a “change in control” (as defined in the Company’s 2015 Long Term Incentive Plan), then the participant will be eligible to receive the following benefits:

In addition, if a Plan participant’s employment with the Company terminates due to the participant’s death or disability, then the participant will be eligible to receive the following benefits:

In order to receive severance benefits under the Plan, participants must execute (and not revoke) a release of claims in favor of the Company and its affiliates and comply with certain restrictive covenants, including a one-year post-employment restriction against solicitation of Company employees and customers and a perpetual restriction against disclosure of confidential information and against disparagement of the Company and any of its officers, partners and stockholders.

The Plan does not provide for a gross-up payment to any eligible executive to offset any excise taxes that may be imposed on excess parachute payments under Section 4999 of the Internal Revenue Code or any similar federal, state, or local tax that may be imposed.  If the severance benefits under the Plan would trigger such an excise tax for a participant, the Plan provides that the participant’s severance benefits will be reduced to a level at which the excise tax is not triggered, unless the participant would receive a greater amount without such reduction after taking into account the excise tax and other applicable taxes.

Appointment of Rod Skaufel as President, Operations

 

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Effective August 16, 2016, Rod Skaufel will be appointed President, Operations of the Company.  Mr. Skaufel has had more than 30 years of experience in the oil and gas industry and brings deep technical capability and strategic focus. Mr. Skaufel most recently served as Head of Strategic Planning, Corporation for BHP Billiton and was the head of strategic planning, value management and the investment office.  Mr. Skaufel joined BHP Billiton in 2007 and, prior to his promotion to his most recent position, served as President, North America Shale from 2013 to 2015.  Prior to that, in 2012 he held the title of President, Conventional Business.  He also led BHP Billiton’s engineering function and Central Engineering organization comprised of subject matter expert in deepwater floating systems including subsea, subsurface, and umbilical.  Mr. Skaufel joined BHP Billiton from ExxonMobil where he served as Technical Operations Manager – Chad-Cameroon from 2003 to 2007 and Planning Advisor from 2000 to 2003. Mr. Skaufel began his career in 1985 with Mobil Oil Corporation and held progressively more senior roles until he joined ExxonMobil. Mr. Skaufel holds a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.

In connection with Mr. Skaufel’s appointment as President, Operations, Mr. Skaufel will be paid an annual base salary of $625,000 and will receive initial equity awards of (i) 156,250 service-vesting restricted shares of the Company’s common stock (the “Service-vesting Award”) under the Company’s Long Term Incentive Plan and (ii) 156,250 performance- and service-vesting restricted share units (the “Performance-vesting Award”) under the Company’s 2015 Long Term Incentive Plan. The Service-vesting Award will vest in three equal installments on each of the first three anniversaries of the grant date, subject to Mr. Skaufel’s continued employment with the Company on each such date (the “Service Condition”). The Performance-vesting Award will vest in three equal installments on each of the first three anniversaries of the grant date only if on the applicable anniversary date, the Service Condition has been met and the Company’s performance equals at least 90% of the performance of the Russell Energy MidCap Index for the preceding year. In addition, for each year of Mr. Skaufel’s employment with the Company, Mr. Skaufel will be eligible to receive a discretionary annual bonus with a target value of 75% of his base salary, which will be prorated for 2016, and a discretionary annual incentive plan award of up to 150% of his base salary.

This appointment is part of a restructuring of the senior leadership team, as a result of which the position of Chief Operating Officer has been eliminated. James H. Painter, who currently serves as interim Chief Operating Officer, will continue to serve as the Company’s Executive Vice President following Mr. Skaufel’s appointment and work with Mr. Skaufel on operations and development.  

In addition, on July 28, 2016, the Board of Directors of the Company appointed William P. Utt as Non-Executive Chairman of the Board of Directors of the Company and James W. Farnsworth as President, Exploration.  

 

 

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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.

 

 

Dated: August 2, 2016

 

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EXHIBIT INDEX

 

 

 

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