UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

(Mark One)

For the fiscal year ended December 31, 2017

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)

 

 

 

Cobalt Center

920 Memorial City Way, Suite 100

Houston, Texas 77024

(Address of principal executive offices, including zip code)

(713) 579-9100

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Securities Act:

 

Securities registered pursuant to Section 12(g) of the Securities Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐    No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act. Yes ☐    No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒    No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒    No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

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

 

(Check one):

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Act). Yes ☐    No ☒

As of June 30, 2017, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common stock held by non-affiliates was approximately $66.6 million.

As of January 31, 2018, the registrant had 29,924,817 shares of common stock outstanding.

 

 

 

 

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Cobalt International Energy, Inc. 

 

 

 

 

 

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Cautionary Note Regarding Forward–Looking Statements

 

This Annual Report on Form 10–K contains forward–looking statements within the meaning of the federal securities laws including, but not limited to, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (each a “forward–looking statement”).  We have based our forward–looking statements 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 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 risk factors identified in Item 1A of this Annual Report on Form 10–K, may have a material adverse effect on our results as indicated in forward–looking statements.  You should read this Annual Report on Form 10–K 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 forward-looking statements may be influenced by the following factors, among others:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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The words “anticipate,” “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “intend,” “could,” “expect,” “plan,” “project” and other similar expressions, and the negative thereof, are intended to identify forward–looking statements.  These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information.  The 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.  All of our forward–looking information involve risks and uncertainties that could cause actual results to differ materially from the results expected.  Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of these risk factors identified in “Item 1A. Risk Factors” in this Annual Report on Form 10–K.

 

 

 

 

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PART I

 

Overview

 

Cobalt International Energy, Inc. (“we,” “our,” or “us”) 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.

 

Chapter 11 Proceedings

 

On December 14, 2017 (the “Petition Date”), we and certain of our subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).  The Chapter 11 Cases have been consolidated for procedural purposes only and are being jointly administered under the caption “In re Cobalt International Energy, Inc., et al.”  Bankruptcy Court filings and other information related to the Chapter 11 Cases are available at a website administered by the notice and claims agent at www.kccllc.net/cobalt.  

 

On December 21, 2017, an official committee of unsecured creditors was appointed in the Chapter 11 Cases.  No trustee has been appointed.  We are currently operating our business and properties as debtors and debtors–in–possession subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.  To ensure continued ordinary course operations, the Company received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize the Company to pay employee wages and benefits, pay taxes and certain governmental fees and charges, maintain its existing cash management system and other customary relief.  

 

Subject to certain exceptions provided for in Section 362 of the Bankruptcy Code, all judicial and administrative proceedings against the Debtors or its property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against the Debtors or its property for claims arising prior to the Petition Date was automatically enjoined.  This prohibits, for example, the Debtors’ lenders or noteholders from pursuing claims for defaults under the Debtors’ debt agreements and the Debtors’ contract counterparties from pursuing claims for defaults under their contracts.  Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of the Debtors’ prepetition liabilities and obligations will be settled or compromised under the Bankruptcy Code as part of our Chapter 11 Cases.

 

We intend to consummate a sale of all or substantially all of the Debtors’ assets in the Chapter 11 Cases.  On the Petition Date, the Debtors filed a motion seeking Bankruptcy Court approval of certain bidding procedures and a timeline for the sale process.  On January 25, 2018, the Bankruptcy Court entered the Order (I) Approving Bidding Procedures for the Sale of the Debtors’ Assets, (II) Scheduling an Auction, (III) Approving the Form and Manner of Notice Thereof, (IV) Scheduling Hearing and Objection Deadlines with Respect to the Debtors’ Disclosure Statement and Plan Confirmation, and (V) Granting Related Relief [Docket No. 299] that, among other things, established (i) 5:00 p.m. (prevailing Central Time) on February 22, 2018 for the final bid deadline for all sale transactions, and (ii) 10:00 a.m. (prevailing Central Time) on March 6, 2018 for an auction, if needed.  The Debtors are seeking authority, on and after the confirmation date of their chapter 11 plan, to consummate the sale transactions pursuant to the terms of the sale transaction documentation, the chapter 11 plan, and the order confirming the chapter 11 plan.

 

U.S. Gulf of Mexico

 

Our U.S. Gulf of Mexico operations target oil–focused prospects in the subsalt Miocene and Inboard Lower Tertiary horizons in the deepwater U.S. Gulf of Mexico.  These horizons are characterized by well–defined hydrocarbon systems, comprised primarily of high quality source rock and oil, and contain several of the most significant hydrocarbon discoveries in the deepwater U.S. Gulf of Mexico in recent years.

 

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Our operations in the U.S. Gulf of Mexico consist of four discoveries: Heidelberg, North Platte, Shenandoah and Anchor.  As of December 31, 2017, we also owned interests in 121 blocks within the deepwater U.S. Gulf of Mexico, representing approximately 679,680 gross (361,152 net) acres.  

 

Heidelberg

 

The Heidelberg field is located approximately 140 miles south of Port Fourchon off the Louisiana coast in 5,300 feet of water in the Green Canyon area.  Anadarko Petroleum Corporation (“Anadarko”) is the operator, and we own a 9.375% working interest.  The Heidelberg field was discovered in 2009, appraised in 2012, formally sanctioned in 2013 and began initial production in early 2016.  

 

Heidelberg is currently producing approximately 35,500 BOE per day gross from five wells.  As of December 31, 2017, our share of the Heidelberg field had estimated net proved reserves of 1.1 MMBbls of oil, 0.4 Bcf of natural gas and 0.05 MMBbls of natural gas liquids, or 1.3 MMBOE, and a standardized measure of $17.3 million.  This oil, natural gas and natural gas liquids reserve information is derived from our reserve report prepared by Netherland, Sewell and Associates, Inc. (“NSAI”), our independent reserve engineering firm.  

 

North Platte

 

The North Platte field is located approximately 190 miles south of Port Fourchon off the Louisiana coast in 4,500 feet of water in the Garden Banks area. We are the operator, and we own a 60% working interest.

 

In 2017, we completed our appraisal program at North Platte.  In December 2017, we filed for a suspension of production (“SOP”) with the Bureau of Safety and Environmental Enforcement (“BSEE”).  If BSEE does not grant an SOP, or if operations at North Platte are not resumed, the unit and the leases will terminate in June 2018.  As a contingency to the SOP process, we are also currently in the planning stages for an additional well.

  

Shenandoah  

 

The Shenandoah field, in which we currently own a 20% working interest, is located approximately 170 miles south of Port Fourchon off the Louisiana coast in 5,800 feet of water in the Walker Ridge area.  In December 2017, we received notices from Anadarko Petroleum Corporation and Conoco Phillips Company, our partners in the Shenandoah field, of their intent to withdraw from the project.  Their withdrawals became effective in February 2018.  We are currently working with our partners to determine the impact of these withdrawals on operatorship and the allocation of interests.  Absent obtaining an SOP or commencing well operations at Shenandoah, the unit and lease will terminate in April 2018.

 

In 2017, Anadarko expensed all of its capitalized costs associated with Shenandoah and disclosed that it had “currently suspended further appraisal activities.”  As a result of this disclosure, we determined that Shenandoah was not making sufficient progress and we expensed $236.7 million of suspended exploratory well costs related to Shenandoah.  

 

Anchor  

 

The Anchor field is located approximately 150 miles south of Port Fourchon off the Louisiana coast in 5,183 feet of water. Chevron U.S.A. Inc. (“Chevron”) is the operator, and we own a 20% working interest.

 

In August 2017, the Bureau of Ocean Energy Management (“BOEM”) approved the assignment of 80% of record title interest in leases we owned immediately south of the existing Anchor unit to our co–owners, and in February 2018, BSEE approved the expansion of the Anchor unit to include portions of these two south Anchor leases which will serve to preserve these leases.

 

The appraisal drilling program for the Anchor field concluded in 2017 with the completion of the Anchor #4 well.  In January 2018, Chevron filed an SOP with BSEE.  Approval of the SOP would preserve the leases and the Anchor unit.

 

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Alliance with Total

 

In 2009, we and Total E&P USA, INC. (“Total”) entered into a long–term alliance through a series of transactions in which we and Total combined certain U.S. Gulf of Mexico exploratory lease inventory through the exchange of a 40% interest in our leases for a 60% interest in Total’s leases. Pursuant to the agreement, we formed a reciprocal area of mutual interest with Total that covered substantially all of the deepwater U.S. Gulf of Mexico, subject to certain exclusions. Total’s obligations under the agreement consisted principally of paying its share of certain general and administrative costs relating to our operations in the deepwater U.S. Gulf of Mexico.

In June 2017, Total exercised its option to terminate the alliance in accordance with its rights pursuant to the agreement. 

 

West Africa

 

Offshore Angola and Gabon are characterized by the presence of salt formations and oil bearing sediments located in pre–salt and above salt horizons.  Pre–salt refers to oil accumulations trapped in formations that are beneath and older than the original in–place salt layer.  In pre–salt areas, exploration is focused on potential reservoirs that were deposited prior to salt formation.  We believe the geology offshore Angola (Kwanza Basin) and Gabon (South Gabon Coastal Basin) is an analog to the geology offshore Brazil where several pre–salt discoveries and producing fields are located. The basis for this hypothesis is that 150 million years ago, current day South America and Africa were part of a larger continent that broke apart. As these land masses slowly drifted away from each other, rift basins formed that were filled with organic rich material and sediments, which in time became hydrocarbon source rocks and reservoirs. A thick salt layer was subsequently deposited, forming a seal over the reservoirs. Finally the continents continued to drift apart, forming two symmetric geologic areas separated by the Atlantic Ocean. This symmetry in geology is particularly notable in the deepwater areas offshore Gabon, Angola and the Campos Basin offshore Brazil.

 

Our operations in West Africa consist of Block 20 and Block 21, both offshore Angola, and the Diaba Block offshore Gabon.  

 

Settlement Agreement with Sonangol

 

In August 2015, we executed a Purchase and Sale Agreement (the “Sale Agreement”) with Sociedade Nacional de Combustiveis de Angola–Empresa Publica (“Sonangol”) for the sale by us to Sonangol of the entire issued and outstanding share capital of our indirect wholly–owned subsidiaries, CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold our 40% working interest in each of Block 20 and Block 21 offshore Angola.  The requisite Angolan government approvals were not received within one year from the execution date and the Sale Agreement terminated by its terms in August 2016.

 

In 2016, we recorded an impairment of $1,629.8 million related to our Angolan assets in accordance with Accounting Standards Codification 932, Extractive Activities – Oil and Gas (“ASC 932”), which requires, among other things, that “sufficient progress” be made with respect to oil and natural gas projects in order to avoid the requirement to expense previously capitalized exploratory or appraisal well costs.  Given Sonangol’s delays and failure to grant the extensions as well as the general investment climate in the Angolan oil and natural gas industry, the procedures of ASC 932 required us to record a full impairment of our Angolan assets.  

 

In March 2017, we submitted a Notice of Dispute to Sonangol pursuant to the Sale Agreement.  Subsequently, we filed a Request for Arbitration (“RFA”) with the International Chamber of Commerce (“ICC”) against Sonangol for breach of the Sale Agreement.  Through this arbitration proceeding, we are requesting an award against Sonangol in excess of $2.0 billion, plus applicable interest and costs.  In July 2017, Sonangol filed an Answer to our RFA and Counterclaim, asking for repayment of the $250.0 million initial payment that Sonangol made to us under the Sale Agreement. 

 

We also filed a separate RFA with the ICC against Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) seeking recovery of approximately $162.0 million in unpaid cash calls, plus applicable interest and costs, representing the joint interest receivable owed to us for operations on Block 21 offshore Angola. 

 

 

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On December 19, 2017, certain of our subsidiaries executed a settlement agreement (the “Agreement”) with Sonangol and Sonangol P&P to resolve all disputes and transition our interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. Pursuant to the Agreement, Sonangol is required to pay an initial non–refundable payment of $150.0 million on or before February 23, 2018 (the “Initial Payment”) and the final payment of $350.0 million on or before July 1, 2018 (the “Final Payment”).  On January 25, 2018, the Bankruptcy Court entered an Order Approving Debtors’ Motion for Entry of an Order (I) Authorizing Performance Under Settlement Agreement, (II) Approving Settlement Agreement, and (III) Granting Related Relief [Docket No. 127] authorizing the Debtors’ entry into the Agreement subject to the terms and conditions set forth therein.  The Agreement remains subject to the review of the Bankruptcy Court.

 

On February 21, 2018, we received the Initial Payment from Sonangol and, in accordance with the Agreement, we (i) notified the relevant ICC arbitral tribunal of the agreement between Sonangol P&P and us to terminate the proceedings related to the joint interest receivable owed to us for operations on Block 21 offshore Angola and (ii) notified the relevant ICC arbitral tribunal of the agreement between Sonangol and us to extend the procedural timetable by an additional four months for the proceedings related to the Sale Agreement (the “PSA Arbitration”).

 

In accordance with the Agreement, we and Sonangol are finalizing definitive documentation to implement our exit from Angola and to extinguish all debts and obligations of us and Sonangol to each other that have not already been extinguished pursuant to the Agreement.  Our claims in the PSA Arbitration will be extinguished upon our receipt of the Final Payment, which is due by July 1, 2018.  Within 48 hours of receipt of the Final Payment, we are required under the Agreement to notify the ICC arbitral tribunal in the PSA Arbitration of our agreement to terminate the proceedings related to the dispute arising from the Sale Agreement.  

 

Block 20

 

Block 20 is approximately 1.2 million acres in size, or approximately 200 U.S. Gulf of Mexico blocks, and is centered approximately 75 miles west of Luanda in the deepwater Kwanza Basin.  It is immediately to the north of Block 21.  We are the operator of and hold a 40% working interest in Block 20.  Our partners on Block 20 include BP Exploration Angola (Kwanza Benguela) Limited and Sonangol P&P, with each partner holding a 30% working interest.  We have made four discoveries on Block 20: Orca, Zalophus, Golfhino and Lontra.  

 

We acquired our license to explore for, develop and produce oil from Block 20 by executing a Production Sharing Contract (“PSC”) with Sonangol.  The PSC governs our 40% working interest in and operatorship of Block 20 and forms the basis of our exploration, development and production operations on Block 20.  The PSC provides for an initial exploration period of five years, which expired on January 1, 2017.  Without an extension we believe we are entitled to pursuant to the Sale Agreement, the exploration period for Block 20 has ended.  

 

Block 21

 

Block 21 is approximately 1.2 million acres in size and is 30 to 90 miles offshore Angola in water depths of 1,300 to 5,900 feet in the central portion of the Kwanza Basin.  We are the operator of and hold a 40% working interest in Block 21.  Our partner on Block 21 is Sonangol P&P with a 60% working interest.  We have made three discoveries on Block 21: Cameia, Bicuar and Mavinga.    

 

We acquired our license to explore for, develop and produce oil from Block 21 by executing a Risk Sharing Agreement (“RSA”) with Sonangol.  The RSA governs our 40% working interest in and operatorship of Block 21 and forms the basis of our exploration, development and production operations on this block.  The RSA provides for an initial exploration period of five years.  Pursuant to Executive Decree No. 259/15, this five year period was extended by two years to March 2017.  Without an extension we believe we are entitled to pursuant to the Sale Agreement, the exploration period for Block 21 has ended.  

 

Diaba Block

 

The Diaba Block is approximately 2.2 million acres in size or approximately 370 U.S. Gulf of Mexico blocks. The block is 40 to 120 miles offshore in water depths of 300 to 10,500 feet in the central portion of the offshore

 

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South Gabon Coastal basin.  Total Gabon, S.A. (“Total Gabon”) is the operator and we own a 21.25% working interest.    

 

We acquired our working interest in the Diaba Block offshore Gabon by entering into an assignment agreement with Total Gabon. Through the assignment we became a party to the Production Sharing Agreement (“PSA”) between Total Gabon and the Republic of Gabon. The PSA gives us the right to recover costs incurred and receive a share of the remaining profit from any commercial discoveries made on the block. Under the terms of the PSA and certain approved extensions, acreage not defined by an approved development area expired in January 2018, subject to certain additional extensions.  Total Gabon is currently working with the Gabonese government on the various extension options, but there can be no assurance that the extensions will be granted.  In 2017, we recorded a $45.3 million impairment charge related to our Gabonese assets in accordance with ASC 932.  

 

Oil, Natural Gas and Natural Gas Liquids Data

 

Reserves

 

Our reserve information is derived from our reserve report prepared by NSAI, our independent reserve engineering firm.  Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate.  

 

In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using a combination of deterministic and probabilistic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating of and Auditing of Oil & Gas Reserves information promulgated by the Society of Petroleum Engineers (SPE Standards). NSAI used standard engineering and geoscience methods, or a combination of methods, including volumetric analysis, analogy and reservoir modeling that are considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.

 

The data in the table below represents estimates only. Oil, natural gas and natural gas liquids reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.

 

The following table presents our estimated net proved reserves at December 31, 2017:

 

 

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves (“PUDs”) are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.  As of December 31, 2017, we did not have any reserves that would be classified as PUDs.

 

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The following table describes the changes in our PUDs during 2017:

 

 

Internal Controls Applicable to our Reserve Estimates

 

Our policies and procedures regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations.  

 

Our Reserve Evaluation Policy outlines the process and standards by which reserves are estimated, classified and reported for all our proved reserves, whether they are operated by us or operated by others.  Rod Skaufel, our President, Operations is accountable for the Reserve Evaluation Policy and the completion of the annual and any in–year reserves estimates.  Mr. Skaufel has over 30 years of experience leading oil and natural gas exploration and production operations activities globally.  He has a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.  

 

For each reserve estimation, a qualified technical team is established to provide data to NSAI to enable NSAI to prepare its estimate of the extent and value of the proved reserves of certain of our oil and natural gas properties. Our qualified technical team works with NSAI to ensure the integrity, accuracy and timeliness of data we furnish to NSAI for purposes of their reserve estimation process. Our qualified technical team has significant combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team at a minimum holds a Bachelor of Science degree in petroleum engineering, geology or other relevant degree.

 

The geotechnical, engineering and commercial inputs and interpretations required to calculate the reserves for our portfolio are compiled by our staff, and NSAI is provided full access to information pertaining to the assets and to all applicable personnel. Any differences between reserve estimates internally generated by us and NSAI that exceed established threshold limits are reviewed to ensure the accuracy of the quantifiable data being used in the assessment; available data has been shared and discussed; and that methodologies and assumptions used in the estimations are clearly understood.

 

The principal engineers and geoscientists at NSAI primarily responsible for preparing our reserve estimates are Mr. Joseph J. Spellman and Mr. Ruurdjan (Rudi) de Zoeten.  Mr. Spellman is a Licensed Professional Engineer in the State of Texas (No. 73709) and has over 30 years of practical experience in petroleum engineering.  Mr. de Zoeten is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 3179) and has over 25 years of practical experience in petroleum geosciences.  Both technical principals meet or exceed the education, training, and experience requirements as defined by the standards of the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

The audit committee of our board of directors reviews the processes utilized in the development of our Reserve Evaluation Policy and our reserve report prepared by NSAI annually.

 

 

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Developed and Undeveloped Acreage

 

The following table sets forth information related to our developed and undeveloped acreage as of December 31, 2017:

 

 

 

 

  

The royalties on our lease blocks in the Gulf of Mexico range from 12.5% to 18.75% with an average of 18.26%.

 

Most of our U.S. Gulf of Mexico blocks have a 10 year primary term, expiring between 2018 and 2026. Assuming we are able to commence exploration and production activities or successfully exploit our properties during the primary lease term, our leases would extend beyond the primary term, generally for the life of production.

 

The table below summarizes our undeveloped acreage scheduled to expire in the next five years:

 

 

 

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Drilling Activity

 

The following table summarizes our approximate gross and net interest in wells completed by us during 2017, 2016 and 2015, regardless of when drilling was initiated.  The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the numbers of wells drilled, quantities of reserves found or economic value.

 

 

As of December 31, 2017, we were not participating in the drilling of any wells in the U.S. Gulf of Mexico (including wells that are temporarily suspended).  

 

Productive Wells

 

As of December 31, 2017, we had five gross (0.5 net) productive oil wells in our Heidelberg field.  

 

Drilling Rig Commitments

 

In June 2017, we completed operations at North Platte and released the drilling rig we had previously contracted with Rowan (UK) Reliance Companies plc.  

 

Competition

 

The oil and natural gas industry is highly competitive.  We encounter strong competition from other independent operators and from major and national oil and natural gas companies in acquiring properties, contracting for drilling

 

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equipment and securing trained personnel.  Many of these competitors have financial and technical resources and staffs substantially larger than ours.  As a result, our competitors may be better able to withstand the financial pressures of significant declines in oil and natural gas prices, unsuccessful drill attempts, delays, sustained periods of volatility in financial markets and generally adverse global and industry–wide economic conditions, and may be better able to absorb unsuccessful drill attempts and the burdens resulting from changes in relevant laws and regulations, which would have a material adverse effect on our competitive position.

 

Title to Property

 

We believe that we have satisfactory title to our leasehold and license interests in accordance with standards generally accepted in the oil and natural gas industry.  Our prospect interests are subject to applicable customary royalty and other interests, liens under operating agreements and secured notes, liens for current taxes, and other burdens, easements, restrictions and encumbrances customary in the oil and natural gas industry that we believe do not materially interfere with the use of or affect our carrying value of the prospect interests.  Our 10.75% first lien notes and 7.75% second lien notes are secured by mortgages over substantially all of our oil and natural gas properties in the U.S. Gulf of Mexico.

 

Containment Resources

 

We are a member of several industry groups that provide general and specific oil spill and well containment resources in the U.S. Gulf of Mexico, including HWCG, LLC, formerly Helix Well Containment Group, Clean Gulf Associates, the Marine Preservation Association, and National Response Corporation.  In addition to these memberships, we also have existing contracts with a number of contractors which have equipment that could assist in well containment efforts as well as with the surface effects of a subsea blowout or in addressing a concurrent surface spill. Examples of such equipment include, but are not limited to, anchor and supply vessels, subsea transponders and communication equipment, subsea cutting equipment, debris removal equipment, air and water monitoring and scientific support vessels, remote-operated vehicles, storage and shuttle vessels, and subsea dispersant equipment.

 

Furthermore, we also have contracts in place with Witt–O’Brien’s and The Response Group for the provision of additional emergency response management services to help us address an incident in either the U.S. Gulf of Mexico or West Africa.

 

We are also members of the Oil Spill Response, Ltd. Global Dispersant Stockpile. This membership provides us access to a supply of over one million gallons of dispersant for use in a subsea well control event. This stockpile is stored in six locations around the world in portable containers ready for air freight transport.

 

Insurance Coverage

 

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed.  In general, our current insurance policies cover physical damage to our oil and natural gas assets. The coverage is designed to repair or replace assets damaged by insurable events. Certain of our stated insurance limits scale down to our working interest in the prospect being drilled, including certain operator’s extra expense and third party liability coverage. All insurance recovery is subject to various deductibles or retentions as well as specific terms, conditions and exclusions associated with each individual policy.

 

For our U.S. Gulf of Mexico operations, we purchase (i) operator’s extra expense insurance with limits per well of $650 million, which covers costs to regain control of a well, to redrill the well and for pollution cleanup expenses associated with a loss of well control incident, (ii) third party liability insurance with limits of $200 million including coverage for third party bodily injury or death, property damage and cleanup of pollution on a sudden and accidental basis, and (iii) property insurance for our interest in the Anadarko operated Heidelberg field with limits of full replacement cost value.  We believe that our coverage limits are sufficient and are consistent with our exposure; however, there is no assurance that such coverage will adequately protect us against liability and loss from all potential consequences and damages associated with losses, should they occur.

 

We also purchase director and officer liability insurance. Recoveries under such insurance policies are subject to various deductibles or retentions as well as specific terms, conditions and exclusions. Certain of our insurance providers are disputing coverage for certain expenses and potential liabilities, including with respect to, our current

 

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shareholder litigation matters. We are enforcing our rights to coverage pursuant to our insurance agreements with these insurance providers and believe such expenses and potential liabilities are covered by such insurance, within certain thresholds.  Additional information about this matter is set forth in “Item 3. Legal Proceedings” contained herein.

 

We re–evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may maintain only catastrophic coverage for certain risks in the future.

 

Environmental, Health and Safety Matters and Regulation

 

Our operations are subject to stringent and complex international, foreign, federal, state and local laws and regulations that govern the protection of the environment as well as the discharge of materials into the environment.  These laws and regulations may, among other things:

 

 

 

 

 

 

 

 

 

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.  The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.  Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs.  In general, the oil and natural gas industry continues to be the subject of increased legislation and regulatory attention with respect to environmental matters. The U.S. Environmental Protection Agency (the “EPA”) has renewed environmental compliance by the energy extraction sector as one of its enforcement initiatives through 2019.  

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

 

Oil Exploration

 

Public interest in the protection of the environment and human health has increased, particularly in light of the Deepwater Horizon incident in the U.S. Gulf of Mexico in 2010.  The U.S. government and its regulatory agencies with jurisdiction over oil and natural gas exploration, including the U.S. Department of the Interior (“DOI”) and two of its agencies, the BOEM and the BSEE, which together formerly comprised the Bureau of Ocean Energy

 

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Management, Regulation and Enforcement (“BOEMRE”), responded to this incident by imposing moratoria on drilling operations.  These agencies adopted numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico that are applicable to us and with which our new applications for exploration plans and drilling permits must prove compliant.  

 

Examples of relevant regulations include (i) the Increased Safety Measures for Energy Development on the Outer Continental Shelf—Final Rule, which sets forth increased safety measures for offshore energy development and requires, among other things, that all offshore operators submit written certifications as to compliance with the rules and regulations for operations occurring in the Outer Continental Shelf (“OCS”) including the submission of independent third party written certifications as to the capabilities of certain safety devices, such as blowout preventers and their components, and (ii) the Workplace Safety Rule (including its subsequent revisions), which includes requirements such as the development and implementation of a comprehensive Safety and Environmental Management System (“SEMS”) for oil and natural gas operations.  In December 2017, BSEE published a proposed rule, i.e., the Oil and Gas and Sulphur Operations on the Outer Continental Shelf–Oil and Gas Production Safety Systems-Revisions, which proposes to amend certain provisions of the aforementioned regulations; however, it appears the regulations are currently in effect.

 

In April 2016, BSEE finalized new well control regulations, which include more stringent design requirements and operational procedures for critical well control equipment.  These requirements include those aimed at improving equipment reliability, regulating drilling margin and preventing blowouts, as well as reforms in well design, well control, casing, cementing, real–time well monitoring and subsea containment.  The majority of the requirements became effective in 2016; however, several requirements have more extended timeframes for implementation and compliance.  In December 2017, BSEE submitted a proposed rule to revise these standards, and it is currently under review by the Office of Management and Budget. The regulations required to be implemented in the future could result in some delays of our drilling or production operations.

 

In June 2013, the so–called SEMS II Rule amended the Work Place Safety rule to include additional safety requirements.  Operators, including us, were required to comply with the SEMS II Rule, and have an independent audit completed by June 2015, which we completed in advance of the deadline.  In addition, BSEE proposed revisions in 2013 to 30 CFR 250, subpart H on Oil and Gas Production Safety Systems to address recent technological advances in production safety systems and equipment used to collect and treat oil and natural gas from OCS leases. In September 2016, BSEE published the final rule which includes certain standards concerning the use of best available and safest technology, more rigorous design and testing requirements for boarding shut down valves, and an increase in approved leakage rates for certain safety valves.  These new regulations may result in delays in the permitting process.  As discussed above, these regulations are currently being reconsidered by BSEE.

 

Additionally, the BOEM issues Notices to Lessees (“NTL”) which regulate our operations.  NTL 2015–N01 sets forth requirements for exploration plans, development and production plans and development operations coordination documents and NTL No. 2010–N10 adds certain additional requirements such as reporting, spill containment, and certification.

 

In July 2016, BOEM issued NTL No. 2016-N01 detailing procedures to determine, on an annual basis, a lessee’s ability to carry out its lease obligations – primarily the decommissioning of OCS facilities – and whether to require lessees to furnish additional financial assurance.  In January 2017, BOEM announced its decision to extend the implementation timeline for the NTL by an additional six months as to leases, rights–of–way and rights–of–use and easement for which there are co-lessees and/or predecessors in interest, in order to continue its interactive process to gather additional input from all interested parties, including industry stakeholders.  BOEM is currently reviewing NTL No. 2016–N01 and, during the review period, has extended the implementation timeline beyond the initial June 30, 2017 timeline, except in circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  

 

Resource Conservation and Recovery Act

 

The U.S. Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non–hazardous wastes.  Although drilling fluids, produced waters, and most of the other wastes associated with the exploration,

 

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development and production of oil or natural gas are currently exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA.  Although a substantial amount of the waste generated in our operations is regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”) imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent statutes.  As a result, we could be held liable under CERCLA or analogous state laws for all or part of the costs required to clean up sites where such wastes have been disposed.

 

Clean Water Act

 

The Federal Water Pollution Control Act of 1972, or Clean Water Act, as amended (“CWA”), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, produced waters and other oil and natural gas wastes into waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

Oil Pollution Act

 

The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines.  OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages.  A liable “responsible party” includes the lessee or permittee of the area in which a discharging facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility to cover potential liabilities related to an oil spill for which such person would be statutorily responsible.  The amount depends on the risk represented by the quantity or quality of oil handled by such facility. BSEE has promulgated regulations that implement the financial responsibility requirements of the OPA. A failure to comply with the OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil, administrative and/or criminal enforcement actions.

 

Clean Air Act

 

Our operations are subject to the federal Clean Air Act, (“CAA”), and analogous state laws and local ordinances governing the control of emissions from sources of air pollution.  Our operations utilize equipment that emits air pollutants subject to the CAA and other pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other

 

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requirements of the CAA or other air pollution laws and regulations, including the suspension or termination of permits and monetary fines. The EPA has also issued final source performance standards and permitting requirements aimed to limit emissions of methane, certain volatile organic compounds and toxic air pollutants, such as benzene from new, reconstructed and modified oil and natural gas sources.  The EPA announced in April 2017 its intention to reconsider certain aspects of the Emission Standards for New, Reconstructed, and Modified Sources for the oil and natural gas sector and stay certain requirements; however, the rule is still in effect.  These regulations could require us to incur additional expenses to control air emissions by installing emissions control technologies and adhering to a variety of work practice and other requirements.

 

Climate Change Legislation

 

Our operations and the combustion of petroleum and natural gas based products results in the emission of greenhouse gases (“GHG”) that could contribute to global climate change. Climate change regulation has gained momentum in recent years internationally and domestically at the federal, regional, state and local levels. Some states, regions and localities have adopted or have considered programs to address GHG emissions.  In addition, the U.S. Congress has at times considered the passage of laws to limit GHG emissions. Additionally, it is possible that federal legislation related to GHG emissions will be considered by Congress in the future. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them.

 

In the absence of comprehensive U.S. federal legislation on GHG emission control, the EPA has issued final and proposed regulations pursuant to the CAA to limit carbon dioxide and other GHG emissions. Pursuant to the EPA’s “Mandatory Reporting of Greenhouse Gases” final rule (the “GHG Reporting Rule”), operators of stationary sources emitting more than established annual thresholds of carbon dioxide equivalent GHGs, as well as onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, must monitor, inventory and report the GHG emissions annually. Significant financial expenditures could be required to comply with the monitoring, recordkeeping and reporting requirements under the EPA's GHG reporting program.  We have submitted annual reports for emissions starting with our 2012 GHG emissions. Under EPA regulations finalized in May 2010 (formerly referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The EPA attempted to require the permitting of GHG emissions; although the U.S. Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.

 

In August 2015 the EPA proposed new regulations to reduce methane emissions from oil and natural gas operations in an effort to reduce methane emissions from the oil and natural gas sector by up to 45 percent by 2025. The EPA issued updated and final new source performance standards regulations in 2016 for reducing methane from new and modified oil and natural gas production sources and natural gas processing and transmission sources. In April 2017, EPA indicated that they intend to reconsider certain aspects of the 2016 new source performance standards for the oil and natural gas sector. In June 2017, EPA issued two proposals to stay certain of these requirements and reconsider the entirety of the 2016 rules; however, the rules currently remain in effect.

 

On the international level, in April 2016, 195 nations signed and officially entered into an international climate change accord (the “Paris Agreement”), which calls for member countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. A long–term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre–industrial era. In June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020.  Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. Additionally, under the Kyoto Protocol various nations, including Angola and Gabon, have committed to reducing their GHG emissions. The Kyoto Protocol has been extended until 2020.

 

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could have a material adverse effect on the marketability of the oil, natural gas and natural gas liquids we produce.

 

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Protected Species and Habitats

 

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.  Oil and natural gas exploration and production activities could be prohibited or delayed in areas where protected species or habitats may be located, or expensive mitigation may be required to accommodate such activities.

 

Executive Order 13158, issued in 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose regulations under the CWA to ensure appropriate levels of protection for the marine environment. This order and related CWA regulations have the potential to have a material adverse effect on our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

 

Environmental Issues in Connection with Governmental Approvals

 

Our operations frequently require licenses, permits and other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”), the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals or taking other major agency actions.  OCSLA, for instance, requires the DOI to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment, and gives the DOI authority to refuse to issue, suspend or revoke permits and licenses allowing such activities in certain circumstances, including when there is a threat of serious harm or damage to the marine, coastal or human environment.  Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency must prepare an environmental assessment and, potentially, an environmental impact statement.  If such NEPA documents are required, the preparation of such could significantly delay the permitting process and involve increased costs.  CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development.  In obtaining various approvals from the DOI, we will have to certify that we will conduct our activities in a manner consistent with any applicable CZMA program.  Violation of these foregoing requirements may result in civil, administrative or criminal penalties.

 

Naturally Occurring Radioactive Materials

 

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our operations. Certain oil and natural gas exploration and production activities may enhance the radioactivity, or the concentration, of NORM. In the United States, NORM is subject to regulation primarily under individual state radiation control regulations.  In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; and restrictions on the uses of land with NORM contamination.

 

OSHA and Other Laws and Regulations

 

We are subject to the requirements of OSHA and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information about hazardous materials used or produced in our operations.  Such laws and regulations also require us to ensure our workplaces meet minimum safety standards and provide for compensation to employees injured as a result of our failure to meet these standards as well as civil and/or criminal penalties in certain circumstances.  We believe that we are in substantial compliance with all such existing laws and regulations applicable to our current operations and that our continued compliance

 

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with existing requirements will not have a material adverse impact on our financial condition and results of operations.

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.  Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry may increase our cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Homeland Security Regulations

 

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”) to issue regulations establishing risk–based performance standards for the security of chemical and industrial facilities, including oil and natural gas facilities that are deemed to present “high levels of security risk.” The DHS is currently in the process of adopting regulations that will determine whether our operations may in the future be subject to DHS mandated security requirements. Presently, it is not possible to accurately estimate the costs we could incur, directly or indirectly, to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Exploration and Production

 

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most jurisdictions in which we operate also regulate one or more of the following:

 

 

 

 

 

Federal Regulation of Transportation of Natural Gas

 

The availability, terms and cost of transportation significantly affect sales of natural gas. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

 

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

 

 

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U.S. Coast Guard and the U.S. Customs Service

 

The transportation of drilling rigs to the sites of our prospects in the U.S. Gulf of Mexico and our operation of such drilling rigs is subject to the rules and regulations of the U.S. Coast Guard and the U.S. Customs Service. Such regulation sets safety standards, authorizes investigations into vessel operations and accidents and governs the passage of vessels into U.S. territory. We are required by these agencies to obtain various permits, licenses and certificates with respect to our operations.

 

Laws and Regulations of Angola and Gabon

 

Our exploration and production activities offshore Angola and Gabon are subject to Angolan and Gabonese regulations, respectively.  Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.  Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations.  The following are summaries of certain applicable regulatory frameworks in Angola and Gabon.

 

Angola

 

The petroleum agreements entered with Sonangol set forth the main provisions for exploration and production activities, including fiscal terms, mandatory State participation, obligations to meet domestic supply requirements, local training and spending obligations, and ownership of assets used in petroleum operations.  Angolan law and these agreements also contain important limitations on assignment of interests in such licenses, including in most cases the need to obtain the consent of Angolan authorities.

 

Certain industry specific and general application statutes and regulations govern health, safety and environmental matters under Angolan law.  Prior to commencing petroleum operations in Angola, contractors must, among other things, prepare an environmental impact assessment and establish and implement a health and safety plan.  Such environmental laws govern the disposal of byproducts from petroleum operations and required oil spill preparedness capabilities.  Failure to comply with these laws may result in civil and criminal liability, including, without limitation, fines or penalties.

 

In Angola, petroleum exploration and development activities are governed by the Petroleum Activities Law (the “Angola PAL”). Pursuant to the Angola PAL, all hydrocarbons located underground are property of the State of Angola, and exploitation rights can only be granted by the President of the Republic to Sonangol, as the national concessionaire.  Foreign companies may only engage in petroleum activities in Angola in association with Sonangol through a commercial company or consortium, and generally upon entering a production sharing contract or a risk services agreement.

 

The Angolan PAL and the regulations thereunder extensively regulate the activities of oil and natural gas companies operating in Angola, including financial and insurance requirements, local content and involvement requirements, exploration and development processes, and operational matters.  Local content regulations stipulate which goods or services relating to the oil and natural gas industry must be provided by Angolan companies (being companies which are beneficially owned in their majority by Angolan citizens), whether on a sole basis or in association with foreign contractors, and which goods or services may be provided by foreign companies.  Goods or services which may be provided by foreign companies are generally subject to a local preference rule, whereby Angolan companies are granted preference in tendering for such activities or services, provided that the price difference in such tender does not exceed 10% of the total tendered amount.  The power to make many of the day–to–day decisions concerning petroleum activities, including the granting of certain consents and authorizations, is vested with Sonangol.  New legislation reorganizing the Petroleum Sector currently being proposed could change these powers but, to date, Sonangol’s powers in this respect have not changed.

 

The Foreign Exchange Law for the Petroleum Sector requires, among other things, that all foreign exchange operations be carried out through Angolan banks and that oil and natural gas companies open local bank accounts in foreign currencies in order to pay local taxes, to pay for local petroleum operations related expenses, and to pay for goods and services supplied by both resident and non–resident suppliers and service providers.  As a consequence, foreign currency proceeds obtained by oil and natural gas companies from the sale of their share of production

 

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cannot be retained in full outside Angola, as a portion of the proceeds required to settle tax liabilities and pay for local petroleum operations related expenses must be deposited in and paid through Angolan banks.  

 

The Foreign Exchange Law for the Petroleum Sector was further supplemented by the Banco Nacional de Angola’s (the “BNA”) Order 20/2012.  Under this statute, oil and natural gas companies (including operators) are required to make all payments for goods and services related to Angolan operations provided by non–residents out of bank accounts domiciled in Angola.  In addition, the BNA issued Order 7/14 which determines that oil and natural gas companies shall sell the foreign currency required to pay taxes and other tax dues before the State to the BNA.  The operators shall also sell to BNA the foreign currency necessary to pay foreign exchange residents.

 

Executive Decree 333/13 (“ED 333/13”) had required companies that provide taxable services to oil and natural gas companies to assess the applicable consumption tax, and oil and natural gas companies, as beneficiary of those services, must pay the net value of the service to the service provider and remit the consumption tax to the Angolan government.  ED 333/13 was repealed by Presidential Legislative Decree 3–A/14 which provides that there will be no consumption tax applicable to the oil and natural gas companies which are in the exploration and development phases until first oil, subject to certain exceptions.  Subject to the approval of the Ministry of Finance and Sonangol, oil and natural gas companies may also benefit from the consumption tax exemption during the production phase should those companies demonstrate that the consumption tax causes imbalances which render the petroleum projects not economically viable.

 

Executive Decree 224/12 approved the Operational Discharge Management Regulations which applies to all operational discharges generated during petroleum operations, both onshore and offshore.  It sets the zero discharge prohibition establishing that all operational discharges resulting from onshore activities into the ground, inland waters and coastal waters are prohibited, except where duly justified for safety reasons.  Discharges of (i) drill cuttings contaminated with non–water based drilling muds; (ii) non–water based drilling fluids; and (iii) sands produced resulting from operations in the maritime zone are prohibited and must be brought to shore and be treated as hazardous waste.  This statute requires operators such as ourselves to prepare an Operational Discharge Management Plan for all facilities or groups of facilities under its responsibility.  The statute also establishes that the direct discharge of chemical products into the sea and the use of compounds where the content in aromatics is greater than 1% as a base for the manufacture of drilling fluids are prohibited.  In 2014, Executive Decree 97/14 approved a moratorium on the implementation of the above mentioned regulations.

 

Gabon

 

In 2014, a new Hydrocarbons Law entered into force to regulate oil and natural gas activities in Gabon.  Pursuant to the Hydrocarbons Law, petroleum resources in Gabon are the property of the State of Gabon and petroleum companies undertake operations on behalf of the Government of Gabon. In order to conduct petroleum operations, oil and natural gas companies must enter into a hydrocarbons agreement, typically an exploration and production sharing contract (“EPSC”), with the Minister of Hydrocarbons and the Minister of Economy.  Such agreement is subject to enactment by Presidential Decree, and its provisions must conform to the Hydrocarbons Law, subject to being null and void.

 

All oil and natural gas companies, even those carrying out operations under the previous legal framework, must make payment of two financial contributions set forth in the new Hydrocarbons Law, namely the Investment Diversification Fund (payment of 1% of the Contractor’s turnover during the production phase), and the Hydrocarbons Investment Fund (payment of 2% of the Contractor’s turnover during the production phase), within two years of the entry into force thereof.  Oil and natural gas companies must also, within a maximum of one year from publication of the Hydrocarbons Law, set up and domicile site rehabilitation funds for the Hydrocarbon activities at a Gabonese banking or financial institution.

 

The Hydrocarbons Law provides for a detailed legal framework in terms of organization of the sector, contents and terms and conditions of hydrocarbons agreements, liability, local content, safety and environment, domestic supply requirements, fiscal terms such as production sharing, royalty, bonuses and other charges, corporate income tax, customs, and local training obligations.

 

 

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The powers to make many of the day to day decisions concerning petroleum activities, including the granting of certain consents and authorizations, remain vested with the Hydrocarbons General Directorate, a government authority. In addition, Gabon’s national oil company currently holds, manages and takes participations in petroleum activities on behalf of the State.  Pursuant to the Hydrocarbons Law, the State may acquire an equity stake of up to 20%, at market value, within any companies applying for or already holding an exclusive production authorization.  The contractor must carry the State in its 20% participating interest in the hydrocarbons agreements during the exploration phase.  The parties are free to agree on a higher stake at market value.  Further, the national oil company may also acquire participating interests of up to 15%, at market value.

 

In addition to general local content regulations which require a 90/10  ratio of Gabon national to foreign expatriate workers involved in petroleum activities, pursuant to the Hydrocarbons Law, subcontracting activities are awarded in priority to Gabonese companies in which more than 80% of the workforce consists of Gabonese nationals.  In this respect, only technically qualified license holders may be hired as subcontractors.

Assignment of interests is subject to the Ministry of Hydrocarbons’ consent and to the State’s preemption rights.  Foreign companies carrying out production activities under the form of a local branch must incorporate a local company within two years from the incorporation of the local branch.

 

With respect to natural gas, the State shall enjoy exclusive marketing rights for non–associated natural gas while any non–commercial share of associated natural gas remains the property of the State.

 

Hydrocarbons agreements entered into prior to the Hydrocarbons Law’s publication remain in force until their expiration and should continue to be governed by their own provisions. Our understanding is that the Hydrocarbons Law applies to any issues not expressly dealt with in these contracts’ provisions.

 

Our EPSC governing our license to the Diaba block offshore Gabon was entered into before the publication of the Hydrocarbons Law.  The Diaba EPSC contains a stabilization clause, which provides for the stability of the legal, tax, economic and financial conditions in force at the signing of the EPSC.  Pursuant to the Diaba EPSC, these conditions may not be adversely altered during the term of the agreement; however, we can make no assurance that the Hydrocarbons Law will not have a material adverse effect on our operations or assets in Gabon.

 

Employees

 

As of December 31, 2017, we had 85 employees.  None of these employees are represented by labor unions or covered by any collective bargaining agreement.  We believe that relations with our employees are satisfactory.  In addition, as of December 31, 2017, we had 50 contractors and consultants working in our offices and field locations.

 

Available Information

 

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at www.cobaltintl.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC.  These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549.  Our website also includes our Code of Business Conduct and Ethics and our corporate governance guidelines.  No information from either the SEC’s website or our website is incorporated herein by reference.

 

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EXECUTIVE OFFICERS 

 

The following table sets forth certain information concerning our executive officers as of the date of this Annual Report.

 

 

Timothy J. Cutt has served as Chief Executive Officer since July 2016. Prior to joining Cobalt, Mr. Cutt served as President, Petroleum of BHP Billiton, accountable for its global oil and natural gas business from July 2013 until March 2016.  Mr. Cutt joined BHP Billiton in 2007 as the President of the Production Division in the Petroleum business where he was accountable for running operations in the UK, Pakistan, Trinidad & Tobago, Algeria, Australia and the U.S.  During this time, he was instrumental in building the operating capacity for BHP Billiton’s Deepwater Business. Before joining BHP Billiton, Mr. Cutt held positions in engineering, operations and senior management for 24 years with Mobil Oil Corporation and then ExxonMobil. During this time he spent 10 years supporting exploration and production activities in the Gulf of Mexico and held positions of President Hibernia Management and Development Co. and President of ExxonMobil de Venezuela. Mr. Cutt has a Bachelor of Science Degree in Petroleum Engineering from Louisiana Tech University.

 

David D. Powell joined Cobalt in July 2016 and serves as Chief Financial Officer. Mr. Powell has more than 35 years of experience in the oil and natural gas industry. He previously served as Chief Financial Officer for BHP Billiton – Petroleum and was accountable for all finance, accounting, commercial assurance, supply chain and information technology activities from March 2009 until May 2016. Mr. Powell joined BHP Billiton from Occidental Oil and Gas Corporation where he served as Vice President Houston Finance from November 2007 to February 2009. Mr. Powell began his employment with Occidental Oil and Gas Corporation in 1981 and held progressively more senior roles in the United States, Argentina, Russia, Malaysia and Qatar until he joined BHP Billiton - Petroleum. Mr. Powell started his career in 1980 with the public accounting firm Deloitte, Haskins and Sells. Mr. Powell holds a Bachelor of Science in Accounting, graduating summa cum laude from William Jewell College, he completed the Advanced Management Program at the Harvard Business School and he holds a Certified Public Accountant certificate from the state of Missouri.

 

Rodney M. Skaufel joined Cobalt in August 2016 and serves as President, Operations. Mr. Skaufel has more than 30 years of experience in the oil and natural gas industry and brings deep technical capability and strategic focus. Prior to joining Cobalt, Mr. Skaufel 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 there, he 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 experts in deepwater floating systems including subsea, subsurface, and umbilicals. 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.

 

Jeffrey A. Starzec has served as Executive Vice President, General Counsel and Secretary since February 2015. Mr. Starzec also serves as our Corporate Secretary. Mr. Starzec served as our Senior Vice President and General Counsel from January 2012 to February 2015. From June 2009 until December 2011, Mr. Starzec served as our Associate General Counsel and Corporate Secretary. Prior to joining Cobalt, Mr. Starzec practiced corporate and securities law at Vinson & Elkins LLP from 2006 until 2009, where he represented a variety of energy companies, including Cobalt in connection with its strategic alliance with Total in the U.S. Gulf of Mexico. Mr. Starzec began his legal career at Baker Botts LLP and holds a Bachelor of Science in Economics from Duke University and a J.D. from Harvard Law School.

 

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Richard A. Smith has served as Senior Vice President, Strategy and Business Development since August 2016.  Mr. Smith previously served as Senior Vice President from September 2014 until July 2016.  Prior to that, Mr. Smith served as Senior Vice President and President of Cobalt Angola from November 2013 to September 2014. Mr. Smith served as Vice President, Investor Relations, Compliance and Risk Management from December 2012 until November 2013. Before that, Mr. Smith served as Vice President, Investor Relations and Planning from October 2011 until December 2012. Mr. Smith served as Vice President, International Business Development, Commercial and Finance from September 2010 until October 2011. From October 2007 until September 2010, Mr. Smith served as our Vice President, International. Mr. Smith has over 34 years of oil and natural gas industry experience in North American and international markets. Prior to joining Cobalt, from September 2005 to September 2007, Mr. Smith was Vice President, Joint Venture Development Corporate Affairs for the BP Russia Offshore Strategic Performance Unit, an oil and natural gas exploration and production unit of BP. From February 2002 to August 2005, he held the position of Vice President and then Executive Director for BP Exploration (Angola) Limited, an oil and natural gas exploration and production company operating in Angola. Mr. Smith’s additional industry experience includes leadership positions at various companies in the oil and natural gas industry operating in Azerbaijan, Georgia, Turkey, the United Kingdom, the United States and Canada. Mr. Smith holds a Bachelor of Commerce from the University of Calgary.

 

 

You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10–K, including the consolidated financial statements and the related notes appearing at the end of this Annual Report on Form 10–K.  If any of the following risks actually occurs, our business, business prospects, stock price, financial condition, results of operations or cash flows could be materially adversely affected.  The risks below are not the only ones facing our company.  Additional risks not currently known to us or that we currently deem immaterial may also have a material adverse effect on us.  This Annual Report on Form 10–K also contains forward–looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the risks described below.

 

Risks Relating to Our Chapter 11 Proceedings

 

We are subject to the risks and uncertainties associated with our Chapter 11 Proceedings.

 

On December 14, 2017, the Debtors filed the Chapter 11 Cases as defined and further discussed under “Chapter 11 Proceedings” in Part I, Item 1 “Business” of this Annual Report on Form 10–K.  For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

 

 

 

 

 

 

 

 

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These risks and uncertainties could affect our business and operations in various ways.  For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, vendors, employees, and other interested parties, which in turn could adversely affect our operations and financial condition.  We also need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities.  Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 Cases that may be inconsistent with our goals during the Chapter 11 Cases.

Operating during the Chapter 11 Cases for a long period of time may harm our business.

 

A long period of operations during the Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity.  So long as our Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort diligently pursuing the Chapter 11 Cases instead of focusing exclusively on our business operations.  A prolonged period of operating during the Chapter 11 Cases also may make it more difficult to retain management and other key personnel necessary to the success of our business.  In addition, the Chapter 11 Cases and our expressed intent to sell all or substantially all of our assets makes it likely that our vendors and suppliers will lose confidence in us and will seek to establish alternative commercial relationships.

 

Furthermore, so long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases, and we cannot predict the ultimate amount of all recoveries for the claims that will be subject to a chapter 11 plan.

 

If we are unable to obtain confirmation of our chapter 11 plan on a timely basis, because of a challenge to the plan, a failure to obtain an order from the Bankruptcy Court confirming the plan, or a failure to satisfy the conditions to the effectiveness of the plan, we may be forced to operate in chapter 11 for an extended period of time while trying to develop a different chapter 11 plan that can be confirmed.  Protracted Chapter 11 Cases would increase both the probability and the magnitude of the adverse effects described above.

 

Our shares of common stock are not listed for trading on a national securities exchange.

 

Our common stock currently trades on the OTC Pink marketplace maintained by the OTC Markets Group, Inc. (the “OTC Pink”) and is not listed for trading on a national securities exchange. Investments in securities trading on the OTC Pink are generally less liquid than investments in securities trading on a national securities exchange.

 

We believe it is highly likely that our existing common shares will be canceled in our Chapter 11 Cases.

 

We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure.  As a result, we believe that it is highly likely that our existing common stock will be canceled in our Chapter 11 Cases and will not be entitled to a recovery. Any trading in our common stock during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common stock.

 

We may be unable to sell our Gulf of Mexico assets or all or substantially all of our assets on favorable terms, or at all.

 

Prior to our Chapter 11 Cases, we were engaged in a marketing process for our Gulf of Mexico assets and for the sale of all or substantially all of our assets.  These marketing efforts took longer than anticipated, leading to the commencement of the Chapter 11 Cases to continue our marketing and sale efforts. In connection with our Chapter

 

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11 Cases, we continue to be engaged in a marketing and sale process for our Gulf of Mexico assets and for the sale of all or substantially all of the assets of the Debtors and we may not be able to enter into an agreement to sell our Gulf of Mexico assets or all or substantially all of the assets of the Debtors on favorable terms, or at all.  In the event we do enter into an agreement to sell our Gulf of Mexico assets or all or substantially all of the assets of the Debtors, such agreement may contain closing conditions, including a potential need for certain regulatory approvals and financing, which may be beyond our control.  If we are unable to timely sell our Gulf of Mexico assets or all or substantially all of the Debtors on acceptable terms, or at all, we may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements. 

 

In certain instances, the Chapter 11 Cases may be converted to a case under Chapter 7 of the Bankruptcy Code.

 

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Debtors, the Bankruptcy Court may convert our Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code.  In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code.  The Debtors believe that liquidation under Chapter 7 would result in substantially reduced distributions being made to the Debtors’ creditors than those provided for in a chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than marketing and selling in a controlled manner all or substantially all of the assets  of the Debtors’ as a going concern, (ii) additional administrative expenses resulting from the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of executory contracts in connection with cessation of operations.

 

Our financial results may be volatile and may not reflect historical trends.

 

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims reconciliation and payments significantly impact our consolidated financial statements.  As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Chapter 11 Cases.

 

Transfers of our equity in connection with our Chapter 11 Cases may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

 

Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions.  If we experience an “ownership change,” as defined in Section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations.  Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three–year period.  Following the implementation of a chapter 11 plan, it is possible that an “ownership change” may be deemed to occur.  Under Section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.  Even if the net operating loss carryforwards is subject to limitation under Section 382, the net operating losses can be reduced from the amount of discharge of indebtedness arising in a chapter 11 case under Section 108 of the Internal Revenue Code.

 

Loss of additional personnel could adversely affect our operations.

 

Our operations are dependent on a relatively small group of key management personnel, including our executive officers.  Our Chapter 11 Cases have created distractions and uncertainty for our key management personnel and our employees.  As a result, we have experienced and may continue to experience reductions in force and increased levels of employee attrition.  Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could adversely affect our ability to operate our business.  Our Chapter 11 Cases also have significant potential to adversely affect our ability to retain senior management and key employees.  A loss of key personnel or material erosion of

 

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employee morale could have a material adverse effect on our ability to meet counterparty expectations, thereby adversely affecting our business and results of operations.

 

Risks Relating to Our Business

 

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to execute our development projects and achieve production, conduct exploration and production activities or renew our exploration portfolio.

 

In 2017, we generated $53.9 million of oil, natural gas and natural gas liquids revenues.  Our capital outlays and operating expenditures have increased substantially over at past several years as we expanded our operations and have vastly exceeded the revenue we received from our oil and natural gas operations.  Developing major offshore oil and natural gas projects, especially in complex and challenging environments, continuing exploration activities and obtaining additional leases or concessional licenses and seismic data are very capital intensive.

 

Our future capital requirements will depend on many factors, including:

 

 

 

 

 

 

 

 

 

 

 

 

Additional financing may not be available on favorable terms, or at all, due to the Chapter 11 Cases, our substantial level of indebtedness or otherwise. Even if we succeed in selling additional securities to raise additional capital, at such time the ownership percentage of our existing stockholders could be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that would restrict our business activities. If we choose to farmout interests in our leases or licenses, we would dilute our ownership interest subject to the farmout and any potential value resulting therefrom, and we may lose operating control over such leases or licenses.

 

In response to another decline in oil and natural gas prices, our partners could elect not to participate in the drilling of a particular exploration or appraisal well with us. This could dramatically increase our share of the costs of such operation and may cause us to cancel or delay certain operations and could have a material adverse effect on our liquidity and results of operations.

 

 

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We may be unable to consummate the settlement with Sonangol.

 

On December 19, 2017 we reached a settlement agreement with Sonangol to resolve all disputes and transition Cobalt’s interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. Pursuant to the Order Approving Debtors’ Motion for Entry of an Order (I) Authorizing Performance under Settlement Agreement, (II) Approving Settlement Agreement, and (III) Granting Related Relief [Docket No. 127] (the “9019 Order”), the settlement was authorized and approved by the Bankruptcy Court, but remains subject to its oversight.  We received an initial non–refundable payment of $150.0 million from Sonangol on February 21, 2018 and the final $350.0 million payment is to be received no later than July 1, 2018.  If we are not able to collect the remaining amount owed to us pursuant to our settlement agreement with Sonangol on a timely basis, we will continue to pursue our remedies pursuant to the arbitration proceedings.  There can be no assurances that our efforts will be successful or that we will receive any future payments from Sonangol, which could have a material adverse effect on our business, results of operations and financial condition.

 

Under the terms of our various leases, we are required to drill wells and conduct certain development activities in order to retain exploration and production rights. Failure to do so may result in loss of our interests in these leases.

 

Most of our deepwater U.S. Gulf of Mexico blocks have a 10 year primary term, expiring between 2018 and 2025.  Generally, we are required to commence exploration activities or successfully exploit our properties during the primary lease term in order for these leases to extend beyond the primary lease term.  A portion of the leases covering our North Platte, Shenandoah and Anchor discoveries are beyond their primary term, and the operator must conduct continuous operations or obtain an SOP in order to maintain such leases.  In addition, certain of our targeted exploration prospects have leases that expire within the next 12 months and, even if we were to commence exploration activities prior to lease expiration, we could be required to conduct continuous operations on those prospects if the initial exploration activities were to be successful.  This requirement to conduct continuous drilling operations may cause us to relinquish such leases despite the fact that an exploration well on such leases was successful.  Accordingly, we and our partners may not be able to drill all of the prospects identified on our leases prior to the expiration of their respective terms and we can make no assurances that we, or the operator of the discoveries in which we hold a non–operated interest, will be able to successfully perpetuate leases through continuous operations or obtaining an SOP.  Should the prospects we have identified under the leases currently in place yield discoveries, we cannot assure you that we will not face delays in drilling these prospects or otherwise have to relinquish these prospects.  The costs to maintain leases over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such leases on commercially reasonable terms or at all.  Our actual drilling activities may therefore materially differ from our current expectations, which could have a material adverse effect on our business.  For each of our lease areas, we cannot assure you that any renewals will be granted or whether any new leases will be available on commercially reasonable terms, or, in some cases, at all.

 

A decline in prices for oil and natural gas may have a material adverse effect on our business, financial condition and results of operations.

 

The downturn in oil and natural gas prices during the last few years had, and any future downturn will have, a significant material adverse effect on our business, results of operations, liquidity and the market price of our common stock. The prices that we receive for our oil, natural gas and natural gas liquids production affects our revenues, profitability, liquidity, access to capital and future growth rate. Historically, prices for oil and natural gas have been volatile and will likely continue to be volatile in the future. These prices depend on numerous factors, all of which are beyond our control.  These factors include, but are not limited to:

 

 

 

 

 

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Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:

 

 

 

 

 

 

 

Any future substantial and extended decline in oil and natural gas prices may have a material adverse effect on our future business, financial condition, the market price of our common stock results of operations, liquidity or ability to finance planned capital expenditures.

 

Failure to effectively execute our appraisal and development projects could result in significant delays and/or cost overruns, including the delay of any future production, which could negatively impact our operating results, liquidity and financial position.

 

All of our appraisal and development projects are in the early stages of the project development life-cycle, except for our Heidelberg project.  Our development projects and discoveries will require substantial additional evaluation and analysis, including appraisal drilling and the expenditure of substantial amounts of capital, prior to preparing a development plan and seeking formal project sanction.  First production from these development projects and discoveries is not expected for several years, with the exception of our Heidelberg project which began producing oil and natural gas in 2016.  All of our development projects and discoveries are located in challenging deepwater environments and, given the magnitude and scale of the initial discoveries, will entail significant technical and financial challenges, including extensive subsea tiebacks to production facilities, pressure maintenance

 

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systems, natural gas re-injection systems, and other specialized infrastructure.  This may include the advancement of technology and equipment necessary to withstand the higher pressures associated with producing oil and natural gas from Inboard Lower Tertiary reservoirs.

 

This level of development activity and complexity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. In addition, we have increased dependency on third-party technology and service providers and other supply chain participants for these complex projects.

 

We may not be able to fully execute these projects due to:

 

 

 

 

 

 

 

 

 

We may not be able to compensate for, or fully mitigate, these risks.

 

The productivity of the Heidelberg field is uncertain.

 

Production rates from deepwater oil and natural gas developments may deviate substantially from expectations due to a variety of factors, including unforeseen geologic complexities, inability to maintain adequate pressures within the field reservoir, and failure or non–performance of key production equipment and infrastructure, including production facilities. Deepwater oil and natural gas developments are extremely complex and the downside risks to production levels are especially acute in the early stages of production. If we realize lower production rates than expected from Heidelberg, this may cause a material adverse effect on our results of operations, liquidity and financial condition.

 

We have limited proved reserves and areas that we decide to drill may not yield hydrocarbons in commercial quantities or quality, or at all.

 

We have limited proved reserves and our exploration portfolio consists of identified yet unproven exploration prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons.  The exploration, appraisal and development wells we drill may not yield hydrocarbons in commercial quantities or quality, or at all.  In addition, while our exploration efforts are oil focused, any well we drill may discover natural gas or other hydrocarbons we may not have rights to develop or produce (such as in Angola).  Even when properly used and interpreted, 2–D and 3–D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures.  Undue reliance should not be placed on our limited drilling results or any estimates of the characteristics of our projects or prospects, including any derived calculations of our potential resources or reserves based on these limited results and estimates.  

 

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Additional appraisal wells, other testing and production data from completed wells will be required to fully appraise our discoveries, to better estimate their characteristics and potential resources and reserves and to ultimately understand their commerciality and economic viability.  Accordingly, we do not know how many of our development projects, discoveries or exploration prospects will contain hydrocarbons in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if hydrocarbons are found on our exploration prospects in commercial quantities, construction costs of oil pipelines, production platforms, facilities or subsea infrastructure, as applicable, and transportation costs may prevent such prospects from being economically viable. We will require various regulatory approvals in order to develop and produce from any of our discoveries, which may not be forthcoming or may be delayed.

 

Additionally, the analogies drawn by us from available data from other wells, more fully explored prospects or producing fields may not prove valid in respect of our drilling prospects. We may terminate our drilling program for a prospect if data, information, studies and previous reports indicate that the possible development of our prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our prospects do not prove to be successful, there could be a material adverse effect on our business, financial condition and results of operations.

 

To date, there has been limited exploration, appraisal and development drilling which has targeted the Inboard Lower Tertiary trend in the deepwater U.S. Gulf of Mexico, an area in which we intend to focus a substantial amount of our exploration, appraisal and development efforts.

 

Our discoveries and appraisal and development projects remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and production.

 

Our use of the term “development project” refers to our existing discoveries upon which we have conducted appraisal or development drilling.  Our use of the term “discoveries” refers to our existing discoveries and is not intended to refer to (i) our exploration portfolio as a whole, (ii) prospects where drilling activities have not discovered hydrocarbons or (iii) our undrilled exploration prospects.  A discovery made by the initial exploratory well on a prospect does not ensure that we will ultimately develop or produce hydrocarbons from such prospect or that a development project will be economically viable or successful.  Following a discovery by an initial exploratory well, substantial additional evaluation, analysis, expenditure of capital and partner and regulatory approvals will need to be performed and obtained prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploration and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on future oil and natural gas prices, the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans.

 

Any of the foregoing steps of evaluation and analysis may render a particular development project uneconomic, and we may ultimately decide to abandon the project, despite the fact that the initial exploration well, or subsequent appraisal or development wells, discovered hydrocarbons and where we may have already made a significant investment.  We may also decide to abandon a project based on forecasted oil and natural gas prices or the inability to obtain sufficient financing.  We may not be successful in obtaining partner or regulatory approvals to develop a particular discovery, which could prevent us from proceeding with development and ultimately producing hydrocarbons from such discovery, even if we believe a development would be economically successful.

 

Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause the quantities and net present value of our reserves to be overstated or understated.

 

Numerous uncertainties are inherent in estimating quantities of our reserves. Our estimates of our net proved reserve quantities are based upon reports from NSAI, the independent petroleum engineering firm used by us. The process of estimating oil, natural gas and natural gas liquids reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil, natural gas and natural gas liquids prices, production levels, and operating and development costs. As a result, estimated quantities of proved

 

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reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and natural gas liquids attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

 

The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices for the 12 month period preceding the date of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We are not, and may not be in the future, the operator of all our properties, and do not, and may not in the future, hold all of the working interests in our properties. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.

 

As we do not operate our Heidelberg, Shenandoah and Anchor projects, we are subject to additional risks to our business and financial condition as the ultimate technical, operational and economic success of these projects will depend upon the efforts of the operators of the projects. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future prospects that result in a greater proportion of our prospects being operated by others. In addition, the terms of our current or future licenses or leases may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over the operations of the prospects operated by our partners or which are not wholly-owned by us, as the case may be. Dependence on the operator or our partners could prevent us from realizing our target returns for those prospects. Further, it may be difficult for us to minimize the cycle time between discovery and initial production with respect to prospects for which we do not operate or wholly-own.

 

The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

 

 

 

 

 

 

This limited ability to exercise control over the operations of some of our prospects may cause a material adverse effect on our results of operations and financial condition.

 

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Development drilling may not result in commercially productive quantities of oil and natural gas reserves.

 

Our exploration success has provided us with a number of major development projects on which we are moving forward. We must successfully execute our development projects, including development drilling, in order to generate future production and cash flow. However, development drilling is not always successful and the profitability of development projects may change over time.

 

For example, in new development projects available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. Therefore, a development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. Projects in frontier areas may require the development of special technology for development drilling or well completion and we may not have the knowledge or expertise in applying new technology. All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase.

Our drilling and development plans are scheduled out over several years, making them susceptible to uncertainties that could materially alter their occurrence or timing.

 

Our drilling and development plans on our acreage are scheduled out over a multi-year period. Our drilling and development plans depend on a number of factors, including the availability of capital and equipment, qualified personnel, seasonal and weather conditions, regulatory and block partner approvals, civil and political conditions, oil prices, costs and drilling results. The final determination on whether to drill any exploration, appraisal, or development well, including the exact drilling location as well as the successful development of any discovery, will be dependent upon the factors described elsewhere in this Annual Report on Form 10–K as well as, to some degree, the results of our drilling activities. Because of these uncertainties, we do not know if the drilling locations we have identified or targeted will be drilled in the location we currently anticipate, within our expected timeframe or at all or if we will be able to economically produce oil or natural gas from these or any other potential drilling locations.

 

Further, some of the U.S. Gulf of Mexico leases we own may benefit from unitization with adjacent leases, controlled by third parties. If these third parties are unwilling to unitize such leases with ours, this may necessitate our drilling additional, unforeseen wells to preserve our leases. Failure to drill these wells could result in the loss of acreage through lease expirations. Our actual drilling and development plans and locations may be materially different from our current expectations which could have a material adverse effect our results of operations and financial condition.

 

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

 

Exploring for and developing oil reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating exploration, appraisal and development wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploration wells bear a much greater risk of financial loss than development wells. In the past we have experienced unsuccessful drilling efforts. Moreover, the successful drilling of an oil well does not necessarily result in a profit on investment. A variety of factors, both geological and market-related, can cause a well or an entire development project to become uneconomic or only marginally economic. Our initial drilling sites require significant additional exploration and appraisal, regulatory approval and commitments of resources prior to commercial development. We face additional risks in the Inboard Lower Tertiary trend in the U.S. Gulf of Mexico and offshore Gabon due to a general lack of infrastructure and, in the case of offshore Gabon, underdeveloped oil and natural gas industries and increased transportation expenses due to geographic remoteness. Thus, this may require either a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field.

 

 

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We only recently began producing oil and natural gas and our future performance is uncertain.

 

In January 2016, we began producing oil and natural gas from our Heidelberg project in which we own just a 9.375% working interest. We do not currently produce oil or natural gas from any of our other properties and do not expect to commence production from those properties. We have only been generating revenue from operations for a very short period of time and expect to generate only limited revenue from production during the pendency of our Chapter 11 Cases. Companies in their initial stages of development face substantial business and financial risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities since our inception and expect to continue to incur net losses during the pendency of our Chapter 11 Cases. We face challenges and uncertainties in financial and commercial planning as a result of the complex nature of our business and uncertainties regarding the nature, scope and results of our future activities and financial commitments.

 

The inability of one or more third parties who contract with us to meet their obligations to us may have a material adverse effect on our financial results.

 

We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or lease partners. As a result of our exploration success, we have a large inventory of development projects which will require significant capital expenditures and have long development cycle times. Our partners, both in the U.S. Gulf of Mexico and West Africa, must be able to fund their share of investment costs through the lengthy development cycle, through cash flow from operations, external credit facilities, or other sources, including project financing arrangements. Our partners may not be successful in obtaining such financing, which could negatively impact the progress and timeline for development. In addition to project development costs, our partners must also be able to fund their share of exploration and other operating expenses. We may be unable to recover such outstanding amounts, which would materially negatively impact our liquidity and financial position. Furthermore, in response to the previous decline in oil and natural gas prices, certain of our partners have announced significant capital expenditure reductions, which may cause such partners to elect not to participate in the drilling of a particular exploration or appraisal well with us. This could dramatically increase our share of the costs of such operation and may cause us to cancel or delay certain operations and there could be a material adverse effect on our liquidity and results of operations.

 

In addition, if any of the service providers we contract with to conduct development or exploration activities file for bankruptcy or are otherwise unable to fulfill their obligations to us, we may face increased costs and delays in locating replacement vendors. The previous decline in oil and natural gas prices and the resulting adverse impact on our industry may have an material adverse impact on or contribute to the insolvency of certain third parties from which we contract drilling, development and related oilfield services, as well as block partners, which in turn could affect such companies’ ability to perform such services for us and result in delays to our exploration, appraisal and development activities. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may have a material adverse effect on our business, results of operations or financial condition.

 

We are dependent on certain members of our management and technical team and our inability to retain qualified personnel may impair our ability to grow our business.

 

Our investors must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, discovering and developing oil reserves and progressing our development projects toward first production. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. Our inability to retain qualified personnel may impair our ability to grow our business and develop our discoveries, which could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

We are subject to numerous risks inherent to the exploration and production of oil and natural gas.

 

Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and careful evaluation may not be able to overcome. Our future success will depend on the success of

 

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our exploration and production activities and on the future existence of the infrastructure and technology that will allow us to take advantage of our findings. Additionally, our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

 

Furthermore, the marketability of expected production from our prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of oil and natural gas prices, proximity, capacity and availability of pipelines, the availability of processing facilities, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, importing and exporting of hydrocarbons, environmental, safety, health and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

 

We are subject to drilling and other operational hazards.

 

The exploration and production business involves a variety of operating risks, including, but not limited to:

 

 

 

 

 

 

 

 

 

These risks are particularly acute in deepwater drilling and exploration for natural resources. Any of these events could result in loss of human life, significant damage to property, environmental damage, impairment of our operations, delays in our drilling operations, increased costs and substantial losses. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

We are members of several industry groups that provide general and specific oil spill and well containment resources. Through these industry groups, as described under “Business—Containment Resources”, we have contractual rights to access certain oil spill and well containment resources. We can make no assurance that these resources will perform as designed or be able to fully contain or cap any oil spill, blow-out or uncontrolled flow of hydrocarbons. Furthermore, our contracts for the use of oil spill and well containment resources contain strict indemnity provisions that generally require us to indemnify the contractor for all losses incurred as a result of assisting us in our oil spill and well containment efforts, subject to certain exceptions and limitations. In the event we experience a subsea blowout, explosion, fire, uncontrolled flow of hydrocarbons or any of the other operational risks identified above, the oil spill and well containment resources which we have contractual rights to will not prevent us from incurring losses or shield us from liability, which could be substantial and have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

 

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Our operations involve special risks that could adversely affect operations.

 

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt our operations. As a result, we could incur substantial expenses that could reduce or eliminate capital and funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties.

 

Deepwater exploration generally involves greater operational and financial risks than onshore exploration or exploration in shallow waters. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Such risks are particularly applicable to our deepwater exploration efforts in the Inboard Lower Tertiary trend. In addition, there may be production risks of which we are currently unaware. Whether we use existing pipeline infrastructure, participate in the development of new subsea infrastructure or use floating production systems to transport oil from producing wells, if any, these operations may require substantial time for installation, or encounter mechanical difficulties and equipment failures that could result in significant cost overruns and delays. Furthermore, deepwater operations in the U.S. Gulf of Mexico generally lack the physical and oilfield service infrastructure present in shallower waters. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated hydrocarbons, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of this infrastructure, oil and natural gas discoveries we make in the deepwater, if any, may never be economically producible.

 

In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities for us, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.

 

Our operations may be adversely impacted by tropical storms and hurricanes.

 

Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations in the U.S. Gulf of Mexico as well as operations within the actual and projected path of the tropical storms or hurricanes. In the future, during a shutdown period, we may be unable to access well sites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to offshore drilling rigs and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which may have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

The geographic concentration of our operations subjects us to an increased risk from factors specifically affecting those areas.

 

Our operations are currently concentrated in the deepwater U.S. Gulf of Mexico and offshore West Africa in Angola. In addition, we have an interest in the Diaba Block offshore Gabon. Some or all of these properties could be affected should such regions experience:

 

 

 

 

 

 

 

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For example, in response to the Deepwater Horizon incident in 2010, the U.S. government and its regulatory agencies with jurisdiction over oil and natural gas exploration, including the DOI, BOEM and BSEE, imposed moratoria on drilling operations, required operators to reapply for exploration plans and drilling permits and adopted extensive new regulations, which effectively had halted drilling operations in the deepwater U.S. Gulf of Mexico for a period of time. Additionally, oil and natural gas properties and facilities located in the U.S. Gulf of Mexico were significantly damaged by Hurricanes Katrina and Rita in 2005, which required our competitors to spend a significant amount of time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. We maintain insurance coverage for only a portion of these risks. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. We do not carry business interruption insurance.

 

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

 

We are subject to regulatory risk in the U.S. Gulf of Mexico, and regulations enacted over the past several years may have significantly increased certain of the risks we face and increased the cost of operations in the U.S. Gulf of Mexico.

 

In 2010, the Transocean Deepwater Horizon, a semi-submersible offshore drilling rig operating in the deepwater U.S. Gulf of Mexico, exploded, burned for two days and sank, resulting in loss of life, injuries and a large oil spill. The U.S. government and its regulatory agencies with jurisdiction over oil and natural gas exploration, including the DOI, BOEM and BSEE, responded to this incident by imposing moratoria on drilling operations and adopting numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico. Compliance with these new regulations and interpretations has increased the cost of our drilling operations in the U.S. Gulf of Mexico.

 

In April 2015, BSEE proposed new well control regulations, which include more stringent design requirements and operational procedures for critical well control equipment, including those aimed at improving equipment reliability, regulating drilling margin and preventing blowouts, as well as reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. Certain studies suggest that many wells drilled safely since 2010 could not be drilled as designed under the proposed regulations. If the rule were to be finalized as drafted, certain of our drilling operations may be delayed as required controls are implemented or may become infeasible or impossible due to the increased requirements.

 

Furthermore, the Deepwater Horizon incident has increased and may further increase certain of the risks we face, including, without limitation:

 

 

 

 

 

 

 

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The occurrence of any of these factors, or their continuation, could have a material adverse effect on our business, financial position or future results of operations.

 

We face various risks associated with increased activism against oil and natural gas exploration and development activities.

 

Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as offshore drilling and development. For example, environmental activists have recently challenged lease sales, seismic acquisition activities and decisions to grant air quality permits in the U.S. Gulf of Mexico for offshore drilling.

 

 

 

 

 

 

 

 

 

 

 

 

Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.

 

 

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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act, and any determination that we violated the U.S. Foreign Corrupt Practices Act could have a material adverse effect on our business.

 

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

 

In connection with entering into our RSAs for Blocks 9 and 21 offshore Angola, two Angolan-based E&P companies were assigned as part of the contractor group by the Angolan government. In 2011, a formal order of investigation was issued by the SEC related to allegations of a connection between senior Angolan government officials and one of these companies, and, to avoid non–overlapping information requests, we voluntarily contacted the U.S. Department of Justice (“DOJ”) with respect to the SEC’s investigation and offered to respond to any requests the DOJ may have.

 

We were notified in January 2015 that the SEC’s investigation had concluded and that the SEC did not intend to recommend any enforcement action. In February 2017, we received a letter from the DOJ advising us that the DOJ has closed its investigation into our operations in Angola. This formally concluded the DOJ investigation and no regulatory action was taken against us as a result of these investigations.

 

On March 13, 2017, the SEC informed us that it had initiated an informal inquiry regarding the Sonangol Research and Technology Center (the “SRTC”).  As background, in December 2011, we executed the PSC under which we and BP are required to make certain social contributions to Sonangol, including for the SRTC.  On March 13, 2017, we also received from the SEC a voluntary request for information regarding such inquiry.  We cooperated with the SEC, providing requested information regarding the SRTC.  The SEC also asked for, and we provided, information regarding other aspects of our Angolan operations, including two of our wells offshore Angola.  On January 29, 2018, the SEC formally concluded its investigation into potential violations of the federal securities laws, including the FCPA, and advised that the SEC staff did not intend to recommend any enforcement action by the SEC against us.

 

In the future, we may be partnered with other companies with whom we are unfamiliar. Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the government may seek to hold us liable for successor liability FCPA violations committed by companies in which we invest or that we acquire. There can be no assurance that we will not become subject to additional investigations or inquiries by the SEC, DOJ or other governmental authorities in the future.

 

A change in U.S. energy policy could have a significant impact on our operations and profitability.

 

U.S. energy policy and laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential rules and regulations that could impact the sources and uses of energy in the United States. For example, new CAFE standards enacted in 2012 have resulted in a significant increase in the fuel economy of cars and light trucks and have reduced the future demand for oil for road transport use. GHG emissions regulations may increase the demand for natural gas as fuel for power generation.

 

We design our exploration and development strategy and related capital investment programs years in advance. As a result, we are impacted in our ability to plan, invest and respond to potential changes in our business. This can result in a reduction of our cash flows and profitability to the extent we are unable to respond to sudden or significant changes in our operating environment due to changes in U.S. energy policy.

 

Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.

 

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We operate in a litigious environment.

 

Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and natural gas companies, such as us, can be involved in various legal proceedings, such as title, royalty, or contractual disputes, in the ordinary course of business.

 

We are currently, and from time to time we may become, involved in various legal and regulatory proceedings arising in the normal course of business. We intend to vigorously defend and prosecute any such lawsuits and do not believe they will have a material adverse effect on our business.  On March 8, 2017, we submitted a Notice of Dispute to Sonangol reserving our rights to file an arbitration proceeding under the Sale Agreement if Sonangol does not timely resolve the matters relating to the extensions to our satisfaction and we filed a request for arbitration with the International Chamber of Commerce against Sonangol.  In July 2017, Sonangol filed an Answer to our RFA and Counterclaim, asking for repayment of the $250.0 million initial payment that Sonangol made to us under the Sale Agreement.  We also filed a separate RFA with the ICC against Sonangol P&P seeking recovery of over $___ million, plus applicable post-award interest and costs, representing the joint interest receivable owed to us for operations on Block 21 offshore Angola.    

 

On December 19, 2017, we reached a settlement agreement with Sonangol to resolve all disputes and transition our interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. The Agreement was approved pursuant to the 9019 Order, but remains subject to oversight by the Bankruptcy Court.  An initial non–refundable payment of $150.0 million was paid by Sonangol on February 21, 2018 with the final $350.0 million payment to be received no later than July 1, 2018.  If the Agreement is not consummated, we will continue to seek all available remedies at law or in equity. However, we cannot predict the occurrence or outcome of these proceedings with certainty, and if we are unsuccessful in these litigations and any loss exceeds our available insurance, this could have a material adverse effect on our results of operations.

 

Because we maintain a diversified portfolio of assets that includes both U.S. and international projects, the complexity and types of legal proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

 

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

 

Our oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to civil strife, acts of war, acts of terrorism, piracy, disease, guerrilla activities, insurrection and other political risks, including tension and confrontations among political parties. Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Angola and Gabon.

 

Our operations are exposed to risks of war, local economic conditions, political disruption, civil disturbance and governmental policies that may:

 

 

 

 

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Disruptions may occur in the future, and losses caused by these disruptions may occur that will not be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to, or seek, the exclusive jurisdiction of courts or other tribunals outside the U.S. or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S., which could adversely affect the outcome of such dispute.

 

Our operations may also be adversely affected by laws and policies of jurisdictions, including Angola, Gabon, the United States, the Cayman Islands, Germany and other jurisdictions, or international treaties that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof, could have a material adverse effect on our results of operations and financial position, as well as on the market price of our common stock.

 

The oil and natural gas industry, including the acquisition of exploration acreage worldwide, is intensely competitive.

 

The international oil and natural gas industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of oil and natural gas. We operate in a highly competitive environment for acquiring exploration acreage and hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies may be able to pay more for productive or prospective properties and prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drill attempts, delays, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Our ability to acquire additional exploration prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for available capital for investment in the oil and natural gas industry. As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

Participants in the oil and natural gas industry are subject to complex laws that can affect the cost, manner or feasibility of doing business.

 

Exploration and production activities in the oil and natural gas industry are subject to extensive local, state, federal and international regulations. We may be required to make large expenditures to comply with governmental regulations, particularly in respect of the following matters:

 

 

 

 

 

 

 

 

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Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages for which we may not maintain, or otherwise be protected by, insurance coverage. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

 

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development, production and financial activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.

 

We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and natural gas in increasingly difficult physical environments, such as below-salt deepwater, and global competition for oil and natural gas resources make certain information more attractive to thieves.

 

As dependence on digital technologies has increased, cyber–attacks, including deliberate attacks or unintentional events, have also increased. A cyber–attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial of service on websites.

 

Our technologies, systems, networks, and those of our business partners may become the target of cyber–attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any cyber–attacks, there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber incident. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

 

We and our operations are subject to numerous environmental, health and safety regulations which are subject to change and may also result in material liabilities and costs.

 

We are, and our future operations will be, subject to various international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use and transportation of regulated materials and the health and safety of our employees.  We are required to obtain various environmental permits from governmental authorities for our operations, including drilling permits for our wells.  There is a risk that we have not been or will not be at all times in complete compliance with these permits and the environmental laws and regulations to which we are subject.  If we violate or fail to comply with these laws, regulations or permits, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations.  If we fail to obtain permits in a timely manner or at all (due to opposition from

 

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community or environmental interest groups, governmental delays, changes in laws or the interpretation thereof or any other reasons), such failure could impede our operations, which could have a material adverse effect on our results of operations and our financial condition.

 

We, as the named lessee or as the designated operator under our current and future oil leases, could be held liable for all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our third–party contractors.  To the extent we do not address these costs and liabilities or if we are otherwise in breach of our lease requirements, our leases could be suspended or terminated.  We have contracted with and intend to continue to hire third parties to perform the majority of the drilling and other services related to our operations.  There is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions.  Accordingly, we could be held liable for all costs and liabilities arising out of the acts or omissions of our contractors, which could have a material adverse effect on our results of operations and financial condition.

 

As the designated operator of certain of our leases, we are required to maintain bonding or insurance coverage for certain risks relating to our operations, including environmental risks.  We maintain insurance at levels that we believe are consistent with current industry practices, but we are not fully insured against all risks.  Our insurance may not cover any or all environmental health or safety claims that might arise from our operations or those of our third-party contractors.  If a significant accident or other event occurs and is not fully covered by our insurance, or our third-party contractors have not agreed to bear responsibility, such accident or event could have a material adverse effect on our results of operations and our financial condition.  In addition, we may not be able to obtain required bonding or insurance coverage at all or in time to meet our anticipated startup schedule for each well, and if we fail to obtain this bonding or coverage, such failure could have a material adverse effect on our results of operations and financial condition.

 

Under certain environmental laws, we could be held responsible for all of the costs relating to any releases of regulated substances caused by us or our contractors, at our facilities and at any third party waste disposal sites used by us or on our behalf.  These costs could be material.  In addition, offshore oil exploration and production involves various hazards, including human exposure to regulated substances, including naturally occurring radioactive materials.  As such, we could be held liable for any and all consequences arising out of human exposure to such substances or other damage resulting from the release of regulated substances to the environment, endangered species, property or to natural resources.

 

Particularly since the Deepwater Horizon event in the U.S. Gulf of Mexico in 2010, there has been an increased interest in making regulation of deepwater oil and natural gas exploration and production more stringent in the U.S. If adopted, certain proposals such as a significant increase or elimination of financial liability caps for economic damages, could significantly raise daily penalties for infractions and require significantly more comprehensive financial assurance requirements under OPA which could affect our results of operations and our financial condition.

 

In addition, we expect continued attention to climate change issues.  Various countries and U.S. states and regions have agreed to regulate emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide, a byproduct of oil and natural gas combustion.  Additionally, the U.S. Congress has in the past and may in the future consider legislation requiring reductions in GHG emissions.  The regulation of GHGs and the physical impacts of climate change in the areas in which we and the end-users of our products operate could have a material adverse effect on our operations and the demand for our products.

 

Environmental, health and safety laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future environmental, health and safety laws, and our liabilities arising from releases of, or exposure to, regulated substances may have a material adverse effect on our results of operations and our financial condition. See “Business—Environmental Matters and Regulation.”

 

Non–U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon the sale, exchange or other disposition of our common stock.

 

Our assets consist primarily of interests in U.S. oil and natural gas properties (which constitute U.S. real property

 

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interests for purposes of determining whether we are a U.S. real property holding corporation) and interests in non–U.S. oil and natural gas properties, the relative values of which at any time may be uncertain and may fluctuate significantly over time.  Therefore, we may be, now or at any time while a non–U.S. investor owns our common stock, a U.S. real property holding corporation.  As a result, under the Foreign Investment in Real Property Tax Act (“FIRPTA”), certain non–U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain.  Whether these FIRPTA provisions apply depends on the amount of our common stock that such non–U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market (such as OTC Pink) within the meaning of the applicable Treasury Regulations. So long as our common stock is listed on OTC Pink, only a non–U.S. investor who has held, actually or constructively, more than 5% of our common stock may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.

 

We may incur substantial losses and become subject to liability claims for which we may not have adequate insurance coverage.

 

Several external factors could arise which would significantly impact our ability to effectively insure our oil and natural gas exploration and development operations.  Should legislation be passed to increase the minimum insurance limit of the OSFR policy required for future U.S. Gulf of Mexico oil and natural gas exploration, there is no assurance that we will be able to obtain this insurance.  The insurance markets may not provide products to financially insure us against all operational risks.  For instance, civil and criminal penalties for environmental pollution can be very severe and may not be insurable.  For some risks, we may not obtain insurance if we believe the market price of available insurance is excessive or prohibitive relative to the risks presented.

 

Even when insurance is purchased, exclusions in coverage, unanticipated circumstances and potentially large indemnity obligations may have a material adverse effect on our operations and financial condition.  The inability of our insurance provider to obtain adequate re–insurance may jeopardize our insurance coverage or otherwise impair its ability to perform its obligations under our insurance policies and agreements. Because third–party contractors and other service providers are used in our offshore operations, we may not realize the intended protections of worker’s compensation laws in dealing with their employees.  Generally, under our contracts with drilling and other oilfield service contractors, we are obligated, subject to certain exceptions and limitations, to indemnify such contractors for all claims arising out of damage to our property, injury or death to our employees and pollution emanating from the wellbore, including pollution resulting from blow-outs and uncontrolled flows of hydrocarbons.

 

In addition, even when insurance is purchased, we may encounter disputes with our insurance providers concerning coverage and such providers may attempt to deny coverage.  For example, one of our insurance providers is disputing coverage for certain expenses and potential liabilities, including with respect to our current shareholder litigation matters.  We are enforcing our rights to coverage pursuant to our insurance agreements with this insurance provider and believe such expenses and potential liabilities are covered by such insurance, within certain thresholds.  Should we be unsuccessful in enforcing rights under our insurance agreements, should we breach the terms of our insurance agreements or should such insurance agreements not provide the coverage we believed to be in place, any losses we incur which are not covered wholly or partially by insurance could have a material adverse effect on our results of operations and financial condition.

 

We may be required to pay a material cash sum to Whitton Petroleum Services Limited (“Whitton”) in connection with the closing of the sale of our interests in Blocks 20 and 21 offshore Angola.

 

In February 2009, we entered into a restated overriding royalty agreement (the “Royalty Agreement”) with 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 our 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 our 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, we have 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

 

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and costs. The RSA Economic Model has not yet been agreed with Whitton. If we assign all of our interests in such blocks, or if we sell the company, Whitton may 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, 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 any sale of our interests in Blocks 20 and 21 offshore Angola is uncertain, but may be significant. Resolution of any such payment may include an expert determination of such cash value payment. We can make no assurance that any results from an expert determination process will be favorable to us. If we are ultimately required to pay a significant sum under the Royalty Agreement, there could be a material adverse effect on our business and financial condition.

 

Our arbitration with Sonangol with respect to our interests in Blocks 20 and 21 offshore Angola resulted in the Agreement pursuant to which Sonangol has agreed to pay us $500.0 million to resolve all disputes with Sonangol and transition our interest in Blocks 20 and 21 offshore Angola to Sonangol.  If we are not able to collect the amounts owed to us under the Agreement with Sonangol on a timely basis, we will continue to pursue our remedies available to us.

 

On December 19, 2017, we reached a settlement agreement with Sonangol to resolve all disputes and transition Cobalt’s interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. The Agreement was approved pursuant to the 9019 Order, but remains subject to oversight by the Bankruptcy Court.  An initial non-refundable payment of $150.0 million was paid by Sonangol on February 21, 2018 with the final $350.0 million payment to be received no later than July 1, 2018.  If we are not able to collect the remaining amount owed to us pursuant to the Agreement on a timely basis, we will continue to pursue our remedies pursuant to the arbitration proceedings.  There can be no assurances that our efforts will be successful or that we will receive any future payments from Sonangol, which could have a material adverse effect on our business, results of operations and financial condition.

 

Risks Relating to our Common Stock

 

Our stock price may be volatile, and investors in our common stock could incur substantial losses.

 

The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common stock may be influenced by many factors, including, but not limited to:

 

 

 

 

 

 

 

 

 

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A substantial portion of our total outstanding shares may be sold into the market at any time. This could cause the market price of our common stock to drop significantly, even if our business is doing well.

 

All of the shares sold in our public offerings are freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our “affiliates” as that term is defined in Rule 144 under the Securities Act.  Substantially all the remaining shares of common stock are restricted securities as defined in Rule 144 under the Securities Act.  Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rules 144 or 701 under the Securities Act.  All of our restricted shares are eligible for sale in the public market, subject in certain circumstances to the volume, manner of sale limitations with respect to shares held by our affiliates, and other limitations under Rule 144.  Additionally, we have registered all shares of our common stock that we may issue under our employee and director benefit plans.  These shares can be freely sold in the public market upon issuance, unless pursuant to their terms these stock awards have transfer restrictions attached to them. Sales of a substantial number of shares of our common stock, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our common stock.

 

Ownership of our capital stock is concentrated among our largest stockholders and their affiliates.

 

A small number of stockholders hold a majority of our common stock.  These stockholders have influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions.  This concentration of ownership may limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.  Furthermore, these stockholders may sell their shares of common stock at any time. Such sales could be substantial and adversely affect the market price of our common stock.

 

Provisions of our certificate of incorporation and bylaws could discourage potential acquisition proposals and could deter or prevent a change in control.

 

Some provisions in our certificate of incorporation and bylaws, as well as Delaware statutes, may have the effect of delaying, deferring or preventing a change in control.  These provisions, including those providing for the possible issuance of shares of our preferred stock and the right of the board of directors to amend the bylaws, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire a substantial number of shares of our common stock or to launch other takeover attempts that a stockholder might consider to be in his or her best interest.  These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock.

 

We do not intend to pay dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

 

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Consequently, investors must rely on sales of their shares of common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.

 

 

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None.

 

 

Information regarding our properties is contained in “Item 1. Business” contained herein.

 

 

We are currently, and from time to time we may become, involved in various legal and regulatory proceedings arising in the normal course of business.

 

In November 2014, two purported stockholders, St. Lucie County Fire District Firefighters’ Pension Trust Fund and Fire and Police Retiree Health Care Fund, San Antonio, filed a class action lawsuit in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through November 4, 2014 (the “St. Lucie lawsuit”). The St. Lucie lawsuit, filed against us and certain officers, former and current members of the Board of Directors, underwriters, and investment firms and funds, asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures, primarily regarding compliance with the U.S. Foreign Corrupt Practices Act (“FCPA”) in our Angolan operations and the performance of certain wells offshore Angola.

 

In December 2014, Steven Neuman, a purported stockholder, filed a substantially similar lawsuit against us and certain of our officers in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through August 4, 2014 (the “Neuman lawsuit”). Like the St. Lucie lawsuit, the Neuman lawsuit asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding our compliance with the FCPA in our Angolan operations.

 

In March 2015, the Court entered an order consolidating the Neuman lawsuit with the St. Lucie lawsuit (the “Consolidated Action”) and also entered an order in the Consolidated Action appointing Lead Plaintiffs and Lead Counsel. Lead Plaintiffs filed their consolidated amended complaint in May 2015. Among other remedies, the Consolidated Action seeks damages in an unspecified amount, along with an award of attorney fees and other costs and expenses to the plaintiffs. We filed a motion to dismiss the consolidated amended complaint in June 2015, and the other defendants also filed motions to dismiss. The Court denied our motion to dismiss in January 2016, and, in March 2016, the Court also denied our motion requesting that the Court certify its order on the motions to dismiss so that we may seek interlocutory appellate review of the order.   In June 2017, the Court certified a class of all persons and entities who purchased or otherwise acquired our securities between March 1, 2011 and November 3, 2014.  In July 2017, we filed a petition for permission to file an interlocutory appeal challenging the class certification order.  On August 4, 2017, the Fifth Circuit Court of Appeals granted our petition for permission to file the interlocutory appeal.  We filed our appeal on October 10, 2017, and briefing is now complete.   On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy and the Court stayed the Consolidated Action the following day.  The court presiding over our bankruptcy proceeding subsequently entered an order staying the Consolidated Proceeding in its entirety through April 20, 2018.  On December 22, 2017, Plaintiffs moved to dismiss Cobalt from the Consolidated Action.  The Court denied the motion without prejudice on January 24, 2018, holding that the Plaintiffs could reurge their motion 31 days after providing notice and an opportunity to object to class members via publication in Business Wire.  

 

In May 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

 

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unspecified amount, disgorgement of profits, appropriate equitable relief, and an award of attorney fees and other costs and expenses.  In July 2016, we filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us.  The Court heard arguments on our special exceptions in December 2016.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy.  The matter remains ongoing.

 

In November 2016, McDonaugh, a purported stockholder, filed a derivative action in the 80th District Court in Harris County, Texas against us, as a nominal defendant, and certain of our current and former officers and directors.  The lawsuit alleges that defendants breached their fiduciary duties by failing to maintain adequate internal controls and by permitting or failing to prevent alleged misrepresentations and omissions in our SEC filings and other public disclosures, including in relation to compliance with the FCPA in our Angolan operations and regarding the performance of certain wells offshore Angola.  The lawsuit also alleges that defendants received compensation or other benefits in excess of what they were entitled and that certain officers and directors engaged in unlawful trading and misappropriation of information.  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, reform of our governance and internal controls, restitution and disgorgement of profits, and an award of attorney fees and other costs and expenses.  We filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us in January 2017.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy.  The matter remains ongoing.

 

In April 2017, Hafkey, a purported stockholder, filed a derivative action in the 295th District Court in Harris County, Texas against us, as a nominal defendant, and certain of our current and former officers and directors.  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 exploratory wells offshore Angola; that certain directors caused us to waste corporate assets; and that certain officers received performance–based compensation in excess of what they were entitled. The lawsuit further alleges that demand was wrongfully refused.  The plaintiff asserts claims for breach of fiduciary duty, corporate waste, 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.  We filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us in June 2017.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy.  The matter remains ongoing.

 

We are vigorously defending against the current derivatives lawsuits and do not believe they will have a material adverse effect on our business. However, we cannot predict the occurrence or outcome of these proceedings with certainty, and if we are unsuccessful in these litigations and any loss exceeds our available insurance, this could have a material adverse effect on our results of operations.

 

In May 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 in July 2012 and other claims subsequently submitted to them in connection with our defending against the St. Lucie lawsuit and other investigations and actions.   In December 2016, we amended our petition to add Axis Insurance Company (“Axis”).   Axis provides coverage in excess of the XL policy’s limit of liability.  We allege breach of contract, violation of the Texas Prompt Payment of Claims Act, and seek a declaratory judgment that XL and Axis are obligated to pay any additional loss suffered by us due to the circumstances, investigation, and claims described in the suit.  In December 2016, we also amended our petition to add claims against Illinois National Insurance Company, an AIG subsidiary (“AIG”), which served as our insurer after XL.  Against AIG, we allege breach of contract, violation of the Texas Prompt Payment of Claims Act, violation of the Texas Deceptive Trade Practices-Consumer Protection Act, and seek a declaratory judgment that AIG is obligated to pay any additional loss suffered by us due to the circumstances, investigations, and actions related to the Lontra and/or Loengo wells.  In April 2017, we and certain of our current and former officers and directors (the “Intervenors”) settled claims against XL pursuant to which XL paid $11.5 million.  In October 2017, we and the Intervenors settled claims against Axis pursuant to which Axis has agreed to pay $6.65 million. We continue to pursue our claims against AIG.

 

Please also see “Business—Chapter 11 Proceedings” for a description of our Chapter 11 Cases and “Business—Settlement Agreement with Sonangol” for a description of our arbitration proceedings and settlement with Sonangol, each of which are incorporated into this Item 3 by reference.

 

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Not applicable.

 

PART II

 

Our common stock traded on the NYSE under the symbol “CIE” until December 13, 2017 and subsequently traded on the OTC Pink marketplace under the symbol “CIEI” on December 14, 2017 and “CIEIQ” since December 15, 2017.  At the close of business on February 1, 2018, based on information received from our transfer agent and brokers and nominees, we had approximately 122 holders of record of our common stock.  This number does not include owners for whom our common stock may be held in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

 

On June 16, 2017, we effected a one–for–fifteen reverse stock split of our common stock.  The following table sets forth the range of the daily high and low sales prices, after adjustment to reflect the reverse stock split, for our common stock for 2017 and 2016:

 

 

 

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Corporate Performance Graph 

 

The following graph compares the yearly percentage change in our cumulative total stockholder return on our common stock with the cumulative total return on the published Standard & Poor’s (“S&P”) 500 Stock Index and the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) for the period January 1, 2013 through December 31, 2017.  The graph assumes an investment of $100 was made in our common stock, in the S&P’s Composite 500 Stock Index (with reinvestment of all dividends) and in the Dow Jones U.S. Exploration & Production Index on December 31, 2012 and its relative performance is tracked through December 31, 2017:

 

 

The corporate performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

 

 

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Dividend Policy 

 

With the filing of the Chapter 11 Cases, our ability to pay any dividends is subject to the approval by the Bankruptcy Court.  We have not declared or paid any cash dividends on our common stock, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.  The decision to pay dividends on our common stock is at the discretion of our board of directors and depends on our financial condition, results of operations, capital requirements and other factors that our board of directors deems relevant.

 

Unregistered Sales of Equity Securities

 

None.

 

Issuer Purchases of Equity Securities

 

None.

 

 

The following table shows selected financial data for the periods and as of the dates indicated. The selected financial data are derived from our audited financial statements.  The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.  On June 16, 2017, we effected a one–for–fifteen reverse stock split of our common stock.  All per share data for all periods presented have been adjusted to reflect the reverse stock split on a retroactive basis.  

 

 

 

 

 

 

 

 

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The following discussion of our financial condition and results of operations should be read in conjunction with “Item 8. Financial Statements and supplementary Data” contained herein.  

OVERVIEW

 

We are an independent exploration and production company with operations in the deepwater U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa.  In the U.S. Gulf of Mexico, we have four discoveries: North Platte, Shenandoah, Anchor and Heidelberg.  In West Africa, we have made seven aggregate discoveries offshore Angola on Blocks 20 and 21.  We also have a non–operated interest in the Diaba block offshore Gabon.

 

Chapter 11 Proceedings

 

On the Petition Date, the Debtors filed the Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court.  The Chapter 11 Cases have been consolidated for procedural purposes only and are being jointly administered under the caption “In re Cobalt International Energy, Inc., et al.”  Bankruptcy Court filings and other information related to the Chapter 11 Cases are available at a website administered by the notice and claims agent at www.kccllc.net/cobalt.  

 

On December 21, 2017, an official committee of unsecured creditors was appointed in the Chapter 11 Cases.  No trustee has been appointed.  We are currently operating our business and properties as debtors and debtors–in–possession subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.  To ensure continued ordinary course operations, the Company received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize the Company to pay employee wages and benefits, pay taxes and certain governmental fees and charges, maintain its existing cash management system and other customary relief.  

 

Subject to certain exceptions provided for in Section 362 of the Bankruptcy Code, all judicial and administrative proceedings against the Debtors or its property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against the Debtors or its property for claims arising prior to the Petition Date was automatically enjoined.  This prohibits, for example, the Debtors’ lenders or noteholders from pursuing claims for defaults under the Debtors’ debt agreements and the Debtors’ contract counterparties from pursuing claims for defaults under their contracts.  Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of the Debtors’ prepetition liabilities and obligations will be settled or compromised under the Bankruptcy Code as part of our Chapter 11 Cases.

 

We intend to consummate a sale of all or substantially all of the Debtors’ assets in the Chapter 11 Cases.  On the Petition Date, the Debtors filed a motion seeking Bankruptcy Court approval of certain bidding procedures and a timeline for the sale process.  On January 25, 2018, the Bankruptcy Court entered the Order (I) Approving Bidding Procedures for the Sale of the Debtors’ Assets, (II) Scheduling an Auction, (III) Approving the Form and Manner of Notice Thereof, (IV) Scheduling Hearing and Objection Deadlines with Respect to the Debtors’ Disclosure Statement and Plan Confirmation, and (V) Granting Related Relief [Docket No. 299] that, among other things, established (i) 5:00 p.m. (prevailing Central Time) on February 22, 2018 for the final bid deadline for all sale transactions, and (ii) 10:00 a.m. (prevailing Central Time) on March 6, 2018 for an auction, if needed.  The Debtors are seeking authority, on and after the confirmation date of their chapter 11 plan, to consummate the sale transactions pursuant to the terms of the sale transaction documentation, their chapter 11 plan, and the order confirming the chapter 11 plan.

 

Further, a chapter 11 plan will determine the rights and satisfy the claims of our prepetition creditors and security holders.  The terms and conditions of a chapter 11 plan will be determined through negotiations with our stakeholders and is subject to approval of the Bankruptcy Court.

 

Accounting Standards Codification 852–10, Reorganizations (“ASC 852–10”), applies to entities that have filed a voluntary petition for relief under chapter 11 of the Bankruptcy Code.  In accordance with ASC 852–10,

 

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transactions and events directly associated with the Chapter 11 Cases are required to be distinguished from the ongoing operations of the business.  In addition, ASC 852–10 requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.  

 

Settlement Agreement with Sonangol

 

In August 2015, we executed the Sale Agreement with Sonangol for the sale by us to Sonangol of the entire issued and outstanding share capital of our indirect wholly–owned subsidiaries, CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold our 40% working interest in each of Block 20 and Block 21 offshore Angola.  The requisite Angolan government approvals were not received within one year from the execution date and the Sale Agreement terminated by its terms in August 2016.

 

In 2016, we recorded an impairment of $1,629.8 million related to our Angolan assets in accordance with ASC 932, which requires, among other things, that “sufficient progress” be made with respect to oil and natural gas projects in order to avoid the requirement to expense previously capitalized exploratory or appraisal well costs.  Given Sonangol’s delays and failure to grant the extensions as well as the general investment climate in the Angolan oil and natural gas industry, the procedures of ASC 932 required us to record a full impairment of our Angolan assets.  

 

In March 2017, we submitted a Notice of Dispute to Sonangol pursuant to the Sale Agreement.  Subsequently, we filed an RFA with the ICC against Sonangol for breach of the Sale Agreement.  Through this arbitration proceeding, we are requesting an award against Sonangol in excess of $2.0 billion, plus applicable interest and costs.  In July 2017, Sonangol filed an Answer to our RFA and Counterclaim, asking for repayment of the $250.0 million initial payment that Sonangol made to us under the Sale Agreement. 

 

We also filed a separate RFA with the ICC against Sonangol P&P seeking recovery of approximately $162.0 million in unpaid cash calls, plus applicable interest and costs, representing the joint interest receivable owed to us for operations on Block 21 offshore Angola. 

 

On December 19, 2017, certain of our subsidiaries executed the Agreement with Sonangol and Sonangol P&P to resolve all disputes and transition our interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. Pursuant to the Agreement, Sonangol is required to pay the Initial Payment of $150.0 million on or before February 23, 2018 and the Final Payment of $350.0 million on or before July 1, 2018.  On January 25, 2018, the Bankruptcy Court entered an Order Approving Debtors’ Motion for Entry of an Order (I) Authorizing Performance Under Settlement Agreement, (II) Approving Settlement Agreement, and (III) Granting Related Relief [Docket No. 127] authorizing the Debtors’ entry into the Agreement subject to the terms and conditions set forth therein.  The Agreement remains subject to the review of the Bankruptcy Court.

 

On February 21, 2018, we received the Initial Payment from Sonangol, and, in accordance with the Agreement, we (i) notified the relevant ICC arbitral tribunal of the agreement between Sonangol P&P and us to terminate the proceedings related to the joint interest receivable owed to us for operations on Block 21 offshore Angola and (ii) notified the relevant ICC arbitral tribunal of the agreement between Sonangol and us to extend the procedural timetable by an additional four months for the proceedings related to the Sale Agreement (the “PSA Arbitration”).

 

In accordance with the Agreement, we and Sonangol are finalizing definitive documentation to implement our exit from Angola and to extinguish all debts and obligations of us and Sonangol to each other that have not already been extinguished pursuant to the Agreement.  Our claims in the PSA Arbitration will be extinguished upon our receipt of the Final Payment, which is due by July 1, 2018.  Within 48 hours of receipt of the Final Payment, we are required under the Agreement to notify the ICC arbitral tribunal in the PSA Arbitration of our agreement to terminate the proceedings related to the dispute arising from the Sale Agreement.  

 

CRITICAL ACCOUNTING POLICIES 

 

This discussion and analysis of our financial condition and results of operations is based upon information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States.  The preparation of these consolidated financial statements requires us to

 

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make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities.  Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.  We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable at the time, the results of which form the basis for making judgements about the carrying values of assets and liabilities that are not readily apparent from other sources.  Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.  

 

We have defined a critical accounting policy as one that is both important to the portrayal of either our financial condition and results of operations and requires us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain.  There are other policies within our consolidated financial statements that require us to make estimates and assumptions, but they are not deemed critical as defined above.  We believe that the following are the critical accounting policies used in the preparation of our consolidated financial statements.

 

Oil and Natural Gas Properties

 

We account for our oil and natural gas properties using the successful efforts method of accounting.  Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized.  Oil and natural gas lease acquisition costs are also capitalized.  Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred.  Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over 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 proved developed reserves on a units–of–production basis.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred.  The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.  Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date.  Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results.  Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense.  The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.  Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

 

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable.  Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels.  If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected

 

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present value of the future net cash flows.  Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices.  Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation.  The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area.  Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

 

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

 

Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate.  Reserves for proved developed producing wells were estimated using production performance and material balance methods.  New producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

 

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, development costs and workover costs, all of which may vary considerably from actual results.  In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.  Independent reserve engineers prepare our reserve estimates at the end of each year.

 

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense.  Our reserves are also the basis of our supplemental oil and natural gas disclosures.

 

Accounting for Asset Retirement Obligations

 

We have significant obligations to remove tangible equipment and facilities at the end of oil and natural gas production operations.  Our removal and restoration obligations are primarily associated with dismantling facilities and plugging and abandoning wells.  Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to dismantle facilities or plug and abandon wells.  After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.

 

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the

 

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present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

 

We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

 

Income Taxes

 

We use the liability method to determine our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.  Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered.  Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized.  In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies.  These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets.  The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.

 

We are subject to the jurisdiction of various domestic and foreign tax authorities.  Our operations in these different jurisdictions are taxed on various bases and determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits.  Changes in tax laws, regulations, agreements and treaties, or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

 

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RESULTS OF OPERATIONS 

 

 

Year Ended December 31, 2017 Compared with the Year Ended December 31, 2016

 

Net loss for 2017 was $968.3 million compared with $2,343.3 million for 2016.  The significant factors in the change were (i) a decrease of $1,638.8 million in dry hole costs and impairments, (ii) a decrease of $95.9 million in loss on the amendment of our Rowan contract and (iii) a $37.1 million increase in oil, natural gas and natural gas liquids revenues offset by (iv) $332.8 million of reorganization expenses and (v) a $79.5 million increase in interest expense.

 

Oil, natural gas and natural gas liquids revenues for 2017 increased $37.1 million compared with 2016 due to $28.1 million from higher production at Heidelberg and $9.0 million from improved prices.  

 

Seismic and exploration costs decreased $10.7 million during 2017 compared with 2016 as a result of decreases of $9.2 million of costs in Angola due to lower activity levels and $1.5 million in delay rental payments for our Gulf of Mexico unproved oil and natural gas leaseholds.

 

In 2017, we incurred $328.9 million of dry hole costs and impairments.  Of this amount, $236.4 million related to the write off of costs associated with our Shenandoah discovery, $45.3 million related to the write off of costs associated with our Diaman discovery offshore Gabon, and $44.2 million related to impairment of unproved leaseholds.  In 2016, we incurred $1,967.2 million of dry hole costs and impairments.  Of this amount, $1,629.8 million related to costs associated with our wells and underlying leases in Angola, $195.6 million related to costs associated with the Goodfellow #1 well and sidetrack and the underlying leases, $62.0 million related to the impairment of inventory and other property in Angola and $56.9 million related to costs associated with the Shenandoah #3 well as it is no longer reasonably possible that the wellbore could be used in the development of the project, should a final investment decision be reached.  

 

In 2016, we entered into an amendment to our drilling contract with Rowan and recorded a charge of $95.9 million.

 

Lease operating expenses for 2017 increased $3.5 million compared with 2016.  This increase is driven by a full year of lease operating expenses in 2017 as well as higher production volumes. Unit operating expenses decreased significantly from $18.33 per BOE in 2016 to $9.91 per BOE in 2017 due to higher production volumes.

 

General and administrative (“G&A”) expenses for 2017 decreased $23.3 million compared with 2016.  The decrease was primarily attributable to an overall decrease in expenses related to lower activity levels in Angola and our workforce reduction plan that was undertaken in 2016 offset by an increase of $12.7 million in legal expenses related to costs associated with our securities related litigation and Angolan arbitrations.

 

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Depreciation, depletion and amortization (“DD&A”) for 2017 increased $19.7 million compared with 2016 as a result of $37.4 million from increased production at Heidelberg offset by $17.7 million from a lower unit cost per BOE. The lower average DD&A rate per BOE reflects the change that prices and additional wells had on our reserves estimates.  DD&A was $37.37 per BOE in 2017 compared with $53.21 per BOE in 2016.

 

In 2017, other income of $17.8 million consisted of $18.2 million related to the settlement of claims against XL and Axis offset by net losses of $0.4 million related to sales of excess inventory.  

 

In 2017, loss on embedded derivatives was $15.7 million compared with $2.5 million for 2016.  These losses are attributable to changes in the fair value of our long–term debt, expected recovery rates, the risk–neutral probability of default and the risk–free rates.

 

Interest expense for 2017 increased $79.5 million compared with 2016 due to $76.1 million of increased interest expense related to the effects of the debt exchanges and $39.9 million of decreased interest capitalization as we are no longer capitalizing interest on our Angolan exploratory wells offset by decreases of $31.9 million associated with the amortization of debt discounts and debt issuance costs and $4.6 million associated with our borrowing base facility that was terminated in 2016.

 

In 2017, reorganization expenses were $332.8 million and consisted of $331.8 million of noncash costs to write up our long–term debt to its face value and $1.0 million of advisory and professional fees.  

 

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

 

Net loss for 2016 was $2,343.3 million compared with $694.4 million for 2015.  The significant factors in the change were (i) a $1,504.9 million increase in dry hole costs and impairments; (ii) a $95.9 million loss on the amendment of the Rowan contract; (iii) an $18.1 million increase in DD&A; and (iv) a $17.2 million increase in G&A expenses.  

 

Oil, natural gas and natural gas liquids revenues for 2016 totaled $16.8 million.  These revenues are from the initial production of oil, natural gas and natural gas liquids from the Heidelberg field in the U.S. Gulf of Mexico which came on line in January 2016.  

 

Seismic and exploration costs for 2016 decreased $3.7 million compared with 2015 as a result of decreases of $14.1 million in seismic acquisition costs due to our efforts to control costs and $1.3 million in delay rentals offset by an increase of $11.7 million in other exploration costs primarily related to the write–off of costs of projects that had not yet been sanctioned.  

 

In 2016, we incurred $1,967.2 million of dry hole costs and impairments.  Of this amount, $1,629.8 million related to costs associated with our wells and underlying leases in Angola, $195.6 million related to costs associated with the Goodfellow #1 well and sidetrack and the underlying leases, $62.0 million related to the impairment of inventory and other property in Angola and $56.9 million related to costs associated with the Shenandoah #3 well as it is no longer reasonably possible that the wellbore could be used in the development of the project, should a final investment decision be reached.  In 2015, we incurred $462.2 million of dry hole costs and impairments.  Of this amount, $256.8 million related to the impairment of our Heidelberg field, $151.4 million related to costs association with our Lontra #1 exploratory well offshore Angola, $26.9 million related to impairments of our unproved leaseholds and $18.4 million related to costs associated with our North Platte #2 appraisal well in the U.S. Gulf of Mexico.    

 

In 2016, we announced that we entered into an amendment to our drilling contract with Rowan and recorded a charge of $95.9 million, of which $76.3 million was paid in 2016.  This amendment provides for the early termination of our long–term drilling contract for one of their drillships.  The drilling contract was originally scheduled to terminate in February 2018, but the amendment provides for a contract termination date in March 2017.  

 

Lease operating expenses totaled $7.6 million, or $18.33 per BOE, in 2016.  These lease operating expenses relate to fixed and variable costs of the Heidelberg field and associated transportation costs.

 

 

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G&A expenses for 2016 increased $17.2 million compared with 2015.  The increase was primarily attributable to (i) $19.6 million of fees associated with the Transaction; (ii) a $13.9 million reduction in amounts reimbursed from our partners due to lower activity levels in Angola; and (iii) a $8.1 million increase in legal fees related to our ongoing litigation offset by (iv) a $15.9 million decrease in payroll and equity–based compensation costs due to lower equity–based compensation costs from the reversal of costs related to forfeitures of unvested equity awards associated with our workforce reduction plan and (v) an $8.5 million overall decrease in other expenses due to lower activity levels in Angola and our cost cutting efforts.  

 

DD&A for 2016 increased $18.1 million compared with 2015 due to the recording of depletion on our Heidelberg field.  DD&A was $53.21 per BOE in 2016.

 

Interest expense for 2016 increased $19.7 million compared with 2015 due to $11.2 million of increased interest related to effects of the Transaction, $6.3 million of decreased interest capitalization as we are no longer capitalizing interest on our Angolan exploratory wells, and $2.2 million of net increased interest ($3.3 million of debt issuance costs written off offset by $1.1 million of decreased interest) associated with our borrowing base facility that was terminated in 2016.

 

LIQUIDITY AND CAPITAL RESOURCES

 

As of December 31, 2017, we had approximately $458.3 million in cash and cash equivalents and restricted cash and $2,840.8 million in aggregate principal amount of long–term debt outstanding.  

 

Our ongoing capital and operating expenditures will vastly exceed the revenue we expect to receive from our oil and natural gas operations for the foreseeable future and would require that we raise substantial additional funding.  However, the uncertainty resulting from our Chapter 11 Cases has limited our ability to access the credit and capital markets as a source of funding.    

 

There can be no assurance that we will have sufficient liquidity to continue to fund our operations or allow us to continue as a going concern until a chapter 11 plan is confirmed by the Bankruptcy Court and becomes effective, and thereafter.  Our long–term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court.  

 

Given the uncertainty surrounding the Chapter 11 Cases, there is substantial doubt about our ability to continue as a going concern.  While operating as debtors in possession under chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business.  Further, a chapter 11 plan could materially change the amounts and classifications in our historical consolidated financial statements.

 

Long–term Debt

 

As of December 31, 2017, we have $2,840.8 million in aggregate principal amount of long–term debt outstanding.  For additional information about our long–term debt, please see “Item 8. Financial Statements and Supplementary Data” contained herein.  

 

Royalty Agreement

 

In February 2009, we entered into the Royalty Agreement with 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 our 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 our 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, we have undertaken to agree with Whitton an economic model (the “RSA Economic Model”) containing terms equivalent to

 

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those in such risk services agreement and using actual production and costs. The RSA Economic Model has not yet been agreed with Whitton. If we assign all of our interests in such blocks, or if we sell the company, Whitton may 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, 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 any sale of our interests in Blocks 20 and 21 offshore Angola is uncertain, but may be significant. Resolution of any such payment may include an expert determination of such cash value payment. We can make no assurance that any results from an expert determination process will be favorable to us.  Please see “Item 1A. Risk Factors—We may be required to pay a material cash sum to Whitton Petroleum Services, Ltd. (“Whitton”) in connection with the closing of the sale of our interest in Blocks 20 and 21 offshore Angola.”

Cash Flows

 

Cash flows provided by (used in) type of activity were as follows (in thousands):

 

 

Operating Activities

 

Cash flows from operating activities used $244.5 million and $165.7 million in 2017 and 2016, respectively.  The significant factors in the change were $64.6 of increased interest payments, $19.6 million related to the final payment under the amendment of our U.S. Gulf of Mexico drilling contract, retention bonus payments of $18.6 million and an unfavorable change in working capital.

 

Cash flows from operating activities used $165.7 million and $1.6 million in 2016 and 2015, respectively.  The significant factors in the change were $76.3 million of payments related to the amendment of our U.S. Gulf of Mexico drilling contract, $19.6 million of costs related to the Transaction and an unfavorable change in working capital.

 

Investing Activities

 

In 2017, cash flows provided by investing activities consisted of $867.4 million in proceeds from maturity of our held–to–maturity investments offset by $528.5 million of purchases of held–to–maturity investments and $250.8 million for additions to our oil and natural gas properties.

 

In 2016, cash flows provided by investing activities consisted of $3,390.1 million in proceeds from maturity of our held–to–maturity investments offset by $2,545.9 million of purchases of held–to–maturity investments, $687.9 million for additions to our oil and natural gas properties and $3.5 million of additions to other property.  

 

In 2015, cash flows used in investing activities consisted of $1,999.4 million in proceeds from maturity of our held–to–maturity investments offset by $1,192.9 million of purchases of held–to–maturity investments, $915.9 million for additions to our oil and natural gas properties and $4.8 million of additions to other property.

 

Financing Activities

 

In 2017, we repurchased certain equity–based awards that had been issued to certain officers for $1.3 million as part of a retention program.  

 

In 2016, we received $490.0 million in proceeds from the issuance of our 10.75% first lien notes due 2021.

 

 

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In 2015, we paid $4.0 million of debt issuance costs related to our facility entered into in May 2015.  

 

Contractual Obligations 

 

 

 

 

 

Our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligations at December 31, 2017 is $7.4 million.

 

Off–Balance Sheet Arrangements 

 

As of December 31, 2017, we did not have any off–balance sheet arrangements.

 

RECENT ACCOUNTING STANDARDS

 

Please see “Item 8. Financial Statements and supplementary Data” contained herein for additional information.

 

 

Market risk refers to the risk of loss arising from changes in commodity prices, interest rates, foreign currency exchange rates and other relevant market risks.  We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business.  We may enter into various derivative instruments to manage or reduce market risk, but we will not enter into derivative instruments for speculative purposes.  

Commodity Price Risk

 

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids, which is unchanged from our prior fiscal year.  These prices have historically been volatile, and, as such, future earnings are impacted by changes in these prices.  Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production.  

 

 

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We may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices to our cash flows.  While we currently have no outstanding hedges or similar instruments, any such contracts would be settled with cash and would not require the delivery of physical volumes to satisfy settlement.  While in times of rising commodity prices this strategy may result in our having lower net cash inflows than we would otherwise have if we had not utilized these instruments, management believes the risk reduction benefits of such a strategy could outweigh the potential costs.  

 

 

The information required is included in this report as set forth in the “Index to Consolidated Financial Statements” on page F–1 to this Annual Report on Form 10–K.

 

 

None.

 

 

Evaluation of Disclosure Controls and Procedures 

 

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Management’s Report on Internal Control Over Financial Reporting 

 

Pursuant to Section 404 of the Sarbanes–Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10–K for the fiscal year ended December 31, 2017. Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the caption entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.

 

Changes in Internal Controls Over Financial Reporting 

 

There have not been any changes in our internal controls over financial reporting during the three months ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

None.

 

 

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PART III 

 

 

To the extent necessary to protect investors, the information required by Item 10 will be incorporated by reference from an amendment to this Annual Report on Form 10–K to be filed within 120 days of December 31, 2017.

 

 

To the extent necessary to protect investors, the information required by Item 11 will be incorporated by reference from an amendment to this Annual Report on Form 10–K to be filed within 120 days of December 31, 2017.

 

 

To the extent necessary to protect investors, the information required by Item 12 will be incorporated by reference from an amendment to this Annual Report on Form 10–K to be filed within 120 days of December 31, 2017.

 

 

To the extent necessary to protect investors, the information required by Item 13 will be incorporated by reference from an amendment to this Annual Report on Form 10–K to be filed within 120 days of December 31, 2017.

 

 

To the extent necessary to protect investors, the information required by Item 14 will be incorporated by reference from an amendment to this Annual Report on Form 10–K to be filed within 120 days of December 31, 2017.

 

 

 

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

 

Appraisal well. A well drilled after an exploratory well to gain more information on the drilled reservoirs.

 

Barrel. A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees.

 

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

 

Bcf. One billion cubic feet of natural gas.

 

BOE. One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids.

 

Boepd. One barrel of oil equivalent produced per day.

  

Completion. Installation of permanent equipment for production of oil or natural gas, or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

 

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

Delay rental. Payment made to the lessor under a non–producing oil and natural gas lease at the beginning or end of each year to continue the lease in force for another year during its primary term.

 

Developed oil and natural gas reserves. Reserves of any category that can be expected to be recovered:

 

 

 

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

 

 

 

 

 

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Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole or well. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

DST. Drill stem test.

 

Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.

 

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

 

Farmout. An agreement whereby the owner of the leasehold or working interest agrees to assign a portion of his interest in certain acreage subject to the drilling of one or more specific wells or other performance by the assignee as a condition of the assignment.  Under a farmout, the owner of the leasehold or working interest may retain some interest such as an overriding royalty interest, an oil and natural gas payment, offset acreage or other type of interest.

 

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Gathering system. Pipelines and other facilities that transport oil from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.

 

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

 

Horizon. A zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

 

Leases. Full or partial interests in oil and natural gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas upon payment of rental, bonus, royalty or any other payments.

 

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

 

MBOE. One thousand barrel of oil equivalent.

 

Mcf. One thousand cubic feet of natural gas.

 

MMBbls. One million barrels of oil or other liquid hydrocarbons.

 

MMBOE. One million barrel of oil equivalent.

 

MMcf. One million cubic feet of natural gas.

 

Natural gas.  A combination of light hydrocarbons that, in average pressure and temperature conditions, in found in a gaseous state.  In nature, it is found in underground accumulations and may potentially be dissolved in oil or may also be found in a gaseous state.

 

Natural gas liquids. The hydrocarbon liquids contained within natural gas.

 

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

 

 

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Net pay thickness. The vertical extent of the effective hydrocarbon–bearing rock (expressed in feet).  The net pay thickness encountered by an exploratory well may differ from the mean net pay thickness of the prospect due to several factors, including the relative location of the exploratory well on the structure, potential thickness variations that may occur across the prospect and the extent to which potential reservoir horizons are penetrated.

 

NYMEX. The New York Mercantile Exchange.

 

Oil. Crude oil and condensate.

  

Oil and natural gas lease. A legal instrument executed by a mineral owner granting the right to another to explore, drill and produce subsurface oil and natural gas.  An oil and natural gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.

 

Operator. A party that has been designated as manager for exploration, drilling and/or production on a lease.  The operator is the party that is responsible for (a) initiating and supervising the drilling and completion of a well and/or (b) maintaining the producing well.

 

Play. A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.

 

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

 

 

 

 

 

 

Productive well. An exploratory, development or extension well that is not a dry well.

 

Prospect. Potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled.  The five required elements (generation, migration, reservoir, seal and trap) must be present to work and, if any of them fail, neither oil nor natural gas will be present, at least not in commercial volumes.

 

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

 

Proved reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

66

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 Proved undeveloped reserves (“PUDs”). Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

 

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

 

Royalty. A fractional undivided interest in the production of oil and natural gas wells, or the proceeds therefrom to be received free and clear of all costs of development, operations or maintenance.

 

Spud. The very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth.

 

Standardized measure. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.

 

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

 

Undeveloped oil and natural gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

Workover. Operations on a producing well to restore or increase production.

 

 

 

67

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PART IV

 

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 

 

 

 

(1) Financial Statements

 

 

 

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our consolidated financial statements and related notes.

 

 

The exhibits listed below are filed or furnished as part of this Annual Report on Form 10–K:

 

 

68

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69

---

 

 

70

---

 

 

71

---

 

 

72

---

 

 

 

 

None.

 

 

73

---

 

Exhibit Index

 

 

74

---

 

 

75

---

 

 

76

---

 

 

77

---

 

 

 

 

 

 

78

---

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: March 2, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

 

 

 

 

 

79

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
COBALT INTERNATIONAL ENERGY, INC. 

 

 

 

 

 

F-1

---

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by Securities and Exchange Commission rules adopted under the Securities Exchange Act of 1934, as amended.  Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP).  Our internal control over financial reporting includes those policies and procedures that:

 

 

 

 

There are inherent limitations to the effectiveness of internal control over financial reporting, however well designed, including the possibility of human error and the possible circumvention of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that an internal control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

 

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

 

 

 

 

 

F-2

---

 

Report of Independent Registered Public Accounting Firm

 

To the Stockholders and the Board of Directors of Cobalt International Energy, Inc.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Cobalt International Energy, Inc. (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

 

The Company’s Ability to Continue as a Going Concern

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code and the Company has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events and conditions and management’s plans regarding these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 2, 2018 expressed an unqualified opinion thereon.

 

Basis for Opinion

 

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ Ernst & Young LLP

 

We have served as the Company's auditor since 2006.

Houston, Texas

March 2, 2018

 

F-3

---

 

Report of Independent Registered Public Accounting Firm

 

To the Stockholders and the Board of Directors of Cobalt International Energy, Inc.

 

Opinion on Internal Control over Financial Reporting

 

We have audited Cobalt International Energy, Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework)) (the COSO criteria). In our opinion, Cobalt International Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Cobalt International Energy, Inc. (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements") and our report dated March 2, 2018 expressed an unqualified opinion thereon that included an explanatory paragraph regarding the Company’s ability to continue as a going concern.

 

Basis for Opinion

 

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  

 

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

Definition and Limitations of Internal Control Over Financial Reporting

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

/s/ Ernst & Young LLP

Houston, Texas

March 2, 2018

 

 

 

 

 

F-4

---

 

Cobalt International Energy, Inc. 

(Debtors–in–Possession)

Consolidated Balance Sheets

(In thousands, except number of shares and par value amounts) 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

F-5

---

 

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Consolidated Statements of Operations

(In thousands, except per share data) 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

F-6

---

 

Cobalt International Energy, Inc. 

(Debtors–in–Possession)

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands) 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

F-7

---

 

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Consolidated Statements of Cash Flows

(In thousands) 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

F-8

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

NOTE 1.  ORGANIZATION AND NATURE OF BUSINESS

 

Cobalt International Energy, Inc., together with its wholly–owned subsidiaries (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.  The Company operates in one reportable segment as its chief operating decision maker, the Chief Executive Officer, assesses performance and allocates resources based on the consolidated results of its business.

 

Chapter 11 Cases

 

On December 14, 2017 (the “Petition Date”), the Company and certain of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).  The Chapter 11 Cases have been consolidated for procedural purposes only and are being jointly administered under the caption “In re Cobalt International Energy, Inc., et al.”  Bankruptcy Court filings and other information related to the Chapter 11 Cases are available at a website administered by the notice and claims agent at www.kccllc.net/cobalt.  

 

On December 21, 2017, an official committee of unsecured creditors was appointed in the Chapter 11 Cases.  No trustee has been appointed.  The Debtors are currently operating their business and properties as debtors–in–possession subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.  To ensure continued ordinary course operations, the Company received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize the Company to pay employee wages and benefits, pay taxes and certain governmental fees and charges, maintain its existing cash management system and other customary relief.  

 

Subject to certain exceptions provided for in Section 362 of the Bankruptcy Code, all judicial and administrative proceedings against the Debtors or its property were automatically enjoined, or stayed, as of the Petition Date.  In addition, the filing of new judicial or administrative actions against the Debtors or its property for claims arising prior to the Petition Date was automatically enjoined.  This prohibits, for example, the Debtors’ lenders or noteholders from pursuing claims for defaults under the Debtors’ debt agreements and the Debtors’ contract counterparties from pursuing claims for defaults under their contracts.  Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of the Debtors’ prepetition liabilities and obligations will be settled or compromised under the Bankruptcy Code as part of the Chapter 11 Cases.

 

The Company intends to consummate a sale of all or substantially all of the Debtors’ assets in the Chapter 11 Cases.  On the Petition Date, the Debtors filed a motion seeking Bankruptcy Court approval of certain bidding procedures and a timeline for the sale process.  On January 25, 2018, the Bankruptcy Court entered the Order (I) Approving Bidding Procedures for the Sale of the Debtors’ Assets, (II) Scheduling an Auction, (III) Approving the Form and Manner of Notice Thereof, (IV) Scheduling Hearing and Objection Deadlines with Respect to the Debtors’ Disclosure Statement and Plan Confirmation, and (V) Granting Related Relief [Docket No. 299] that, among other things, established (i) 5:00 p.m. (prevailing Central Time) on February 22, 2018 for the final bid deadline for all sale transactions, and (ii) 10:00 a.m. (prevailing Central Time) on March 6, 2018 for an auction, if needed.  The Debtors are seeking authority, on and after the confirmation date of their chapter 11 plan, to consummate the sale transactions pursuant to the terms of the sale transaction documentation, their chapter 11 plan, and the order confirming the chapter 11 plan.  Further, a chapter 11 plan will determine the rights and satisfy the claims of our prepetition creditors and security holders.  The terms and conditions of a chapter 11 plan will be determined through negotiations with the Company’s stakeholders and is subject to approval by the Bankruptcy Court.

 

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of the Company’s common stock are entitled to receive any distribution or retain any property under a chapter 11 plan.  The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a chapter 11 plan. No assurance can be given as to what distributions, if any, will be made to any of the Company’s creditors or

 

F-9

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

stockholders.  The Company’s chapter 11 plan could result in any of the holders of its liabilities and/or securities, including its common stock, receiving no distribution on account of their interests and cancellation of their holdings. Moreover, a chapter 11 plan can be confirmed, under the Bankruptcy Code, even if the holders of the Company’s common stock vote against the plan and even if the plan provides that the holders of the common stock receive no distribution on account of their equity interests.

 

Accounting Standards Codification 852–10, Reorganizations (“ASC 852–10”), applies to entities that have filed a voluntary petition for relief under chapter 11 of the Bankruptcy Code.  In accordance with ASC 852–10, transactions and events directly associated with the Chapter 11 Cases are required to be distinguished from the ongoing operations of the business.  In addition, ASC 852–10 requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.  

The Company’s non–US subsidiaries are non–debtors and will be accounted for under accounting principles generally accepted in the United States for entities not in bankruptcy and outside the scope of ASC 852–10.  These are minor subsidiaries.  The only material assets of these non–debtor entities are $163.1 million of joint interest receivables, and the only material liabilities of these entities are $96.1 million of social obligation payments and Angolan consumption tax and withholding on services.  The only material expense of the non–debtor entities is $45.3 million of dry hole costs and impairments related to the Company’s exploratory well and leaseholds in Gabon.  There have been no material cash flows in any of these non–debtor entities.

 

Liabilities Subject to Compromise

 

Liabilities subject to compromise in the Company’s consolidated financial statements include pre–petition liabilities that may be affected by a chapter 11 plan at the amounts expected to be allowed, even if they may be settled for lesser amounts.  If there is uncertainty about whether a secured claim is undersecured, or will be impaired under the chapter 11 plan, the entire amount of the claim is included in liabilities subject to compromise.  Differences between liabilities the Company has estimated and the claims to be filed will be investigated and resolved in connection with the claims resolution process in the Chapter 11 Cases.  The Company will continue to evaluate these liabilities throughout the Chapter 11 Cases and adjust amounts as necessary.  Such adjustments may be material.  

 

The following table summarizes the components of liabilities subject to compromise included in the Company’s consolidated balance sheets as of December 31:

 

 

Costs of Reorganization

 

The Debtors have incurred and will continue to incur significant costs associated with the Chapter 11 Cases.  The amount of these costs, which are being expensed as incurred, are expected to significantly affect the Company’s results.  The following table summarized the components included in “Reorganization expenses” in the Company’s consolidated statements of operations:

 

 

 

F-10

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Ability to Continue as a Going Concern

 

Given the uncertainty surrounding the Chapter 11 Cases, there is substantial doubt about the Company’s ability to continue as a going concern. The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.  The consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.  While operating as debtors–in–possession under chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in the Company’s consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business.  Further, a chapter 11 plan could materially change the amounts and classifications in the Company’s historical consolidated financial statements.

 

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation 

 

The consolidated financial statements include the accounts of the Company and its majority–owned subsidiaries (“we,” “our” or “us”).  All significant intercompany accounts and transactions have been eliminated in consolidation.  In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.  

 

On June 16, 2017, we effected a one–for–fifteen reverse stock split of our common stock through an amendment to our second amended and restated certificate of incorporation.  As of the effective time of the reverse stock split, every 15 shares of issued and outstanding common stock were converted into one share of common stock, without any change in par value.  The amendment to our second amended and restated certificate of incorporation also reduced the number of our authorized shares of common stock from 2.0 billion shares to 133.3 million shares.  No fractional shares were issued in connection with the reverse stock split.  Instead, each fractional share was rounded up to the nearest whole share of common stock.  However, any fractional shares resulting from adjustments to the number of shares underlying stock options and stock appreciation rights were rounded down to the nearest whole share of common stock.  All references to shares of common stock, all per share data and all equity compensation activity for all periods presented in the consolidated financial statements and notes to the consolidation financial statements have been adjusted to reflect the reverse stock split on a retroactive basis.  

 

Use of Estimates 

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, 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. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

 

Cash and Cash Equivalents 

 

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.  All of our cash and cash equivalents are maintained with several major financial institutions in the United States.  Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

 

 

F-11

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Restricted Cash

 

Our restricted cash is invested in interest–bearing account.  As of December 31, 2017, $15.4 million of our restricted cash is being held in escrow for the benefit of the insured persons under our settlements with XL Specialty Insurance Company (“XL”) and Axis Insurance Company (“Axis”).  As of December 31, 2017 and 2016, $11.3 million and $2.5 million, respectively, of our restricted cash serves as collateral for certain of our obligations.

 

Joint Interest and Other Receivables 

 

Joint interest receivables result from billing shared costs under the respective operating agreements to our partners.  Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest.  We routinely assess the financial strength of our customers and partners and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.

 

As of December 31, 2017 and 2016, we did not have any reserves for doubtful accounts.  We also did not have any off–balance sheet credit exposure related to our customers.

 

Investments 

 

As of December 31, 2017, all of our investments in marketable debt securities had matured and were included in “Cash and cash equivalents” in our consolidated balance sheet.  Accordingly, there was no potential for other–than-temporary impairments (“OTTI”) as in prior periods.  

 

As of December 31, 2016, our investments in marketable debt securities were classified as held–to–maturity as we had the positive intent and ability to hold the investments until they matured.  Investments with original maturities of greater than three months and remaining maturities of less than one year were classified as short–term investments.

 

These debt securities were carried at amortized cost and the carrying value of these securities was adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities.  As the estimated fair value of each investment approximates its amortized cost, there were no significant unrecognized holding gains or losses as of December 31, 2016.  Income related to these securities was reported as a component of interest income in our consolidated statements of operations. 

 

Investments were considered to be impaired when a decline in fair value was determined to be other–than–temporary.  We conducted a regular assessment of our debt securities with unrealized losses to determine whether these securities had OTTI.  This assessment considered, 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 we intended to sell or whether it was more likely than not that we would be required to sell the debt securities.  As of December 31, 2016, we had no OTTI in our debt securities.

 

Property and Depreciation, Depletion and Amortization

 

Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting.  Under this method, costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are charged to expense as incurred.  For 2017, 2016 and 2015, we recorded dry hole costs and impairments of $282.6 million, $213.5 million and $188.0 million, respectively, to expense costs associated with the drilling of exploratory wells that did not find proved reserves.  

 

Costs for unproved leasehold properties and exploratory wells that find reserves that cannot yet be classified as proved are capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project.  Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or partner approvals, the timing of which is ultimately beyond our control.  Exploratory

 

F-12

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained.  For complex exploratory projects, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while additional appraisal drilling and seismic work is performed on the field or while we seek government or partner approval of development plans.  Our assessment of suspended exploratory well costs is continuous until a determination is made to either sanction the project or to expense the well costs as dry hole costs as sufficient progress has not been made in assessing the reserves and the economic and operating viability of the project. In 2016, we recorded an impairment charge of dry hole costs of $1,276.4 million to expense costs associated with our Angolan exploratory wells (see Note 3).

 

The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

 

Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to ten years. We expense costs for maintenance and repairs in the period incurred. Significant improvements and betterments are capitalized if they extend the useful life of the asset.

 

Impairment of Oil and Natural Gas Properties

 

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable.  The determination of recoverability is made based upon estimated undiscounted future net cash flows.  The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset.  In 2015, we recorded impairment charges of $256.8 million related to our proved oil and natural gas properties (see Note 5).  No impairment charges were recorded in 2017 or 2016 related to our proved oil and natural gas properties.

 

Oil and natural gas leases for unproved properties with a carrying value greater than $1.0 million are assessed individually for impairment based on our current exploration plans and an allowance for impairment is provided if impairment is indicated.  Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized over the terms of the leases at rates that provide for full amortization of leases upon lease expiration.  These leases have expiration dates ranging from 2018 through 2026. For 2017, 2016 and 2015, we recorded impairment charges of $46.2 million, $66.6 million and $26.9 million, respectively, related to our leases for unproved oil and natural gas properties.  In 2016, we also recorded an impairment charge of $353.4 million related to our Angolan leases in conjunction with the write-off of our Angolan exploratory well costs (see Note 3).  

 

Asset Retirement Obligations 

 

An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.

 

Embedded Derivatives

 

Our first lien senior secured notes due 2021 (the “First Lien Notes”) and our second lien senior secured notes due 2023 (the “Second Lien Notes”) include features which were determined to be embedded derivatives requiring bifurcation and accounting as separate financial instruments.  The embedded derivatives were initially recorded at fair value and were subject to remeasurement as of each balance sheet date.  We elected not to designate our embedded derivatives as hedging instruments. Changes in the fair value of these embedded derivatives were recorded immediately to earnings in “Loss on derivatives” in our consolidated statements of operations.

 

 

F-13

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no significant natural gas imbalances at December 31, 2017 and 2016.

 

Income Taxes 

 

We use the liability method to determine our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.  Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered.  Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized.    

 

Concentration of Credit Risk

 

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.  We have experienced no credit losses on such sales in the past.

 

In 2017 and 2016, one customer accounted for 95.0% and 96.5%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of this customer would have a temporary effect on our revenues but, that over time, we would be able to replace this customer.

 

Recently Issued Accounting Standards 

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09, Revenue from Contracts with Customers. This ASU superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to adopt ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We have substantially completed our evaluation of the effects of adopting ASU 2014–09 and have determined the quantitative effects, as well as the related disclosures, will not have a material impact on our consolidated financial statements.  

 

In February 2016, the FASB issued ASU No. 2016-02, Leases.  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 accounting guidance, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily depends on its classification as a finance or operating lease.  However, unlike current accounting guidance, 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 will also require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  Although ASU 2016–02 does not apply to leases for oil and natural gas properties, it does apply to equipment used to explore and develop oil and natural gas resources.  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.  We plan to adopt ASU 2016–02 effective January 1, 2019 and are currently evaluating the impact on our consolidated financial statements and related disclosures.

 

F-14

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

 

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation.  This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows.  We adopted ASU 2016–09 on January 1, 2017 and elected to change our policy to account for forfeitures as they occur rather than by applying an estimated forfeiture rate at the time of grant.  As a result, we recorded a $0.4 million cumulative effect adjustment to beginning accumulated deficit and additional paid in capital on January 1, 2017.  Prior periods have not been retrospectively adjusted.  There was no cumulative effect adjustment for previously unrecognized excess tax benefits as the related deferred tax assets were fully offset by a valuation allowance.

 

No other new accounting pronouncements issued or effective during 2017 have had or are expected to have a material impact on our consolidated financial statements.

 

NOTE 3. ANGOLA SETTLEMENT

 

In August 2015, we executed a Purchase and Sale Agreement (the “Sale Agreement”) with Sociedade Nacional de Combustíveis de Angola—Empresa Pública (“Sonangol”) for the sale by us to Sonangol of the entire issued and outstanding share capital of our indirect wholly–owned subsidiaries, CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold our 40% working interests in each of Block 20 and Block 21 offshore Angola.  The requisite Angolan government approvals were not received within one year from the execution date and the Sale Agreement terminated by its terms in August 2016.  

 

In 2016, we recorded an impairment of $1,629.8 million related to our Angolan assets in accordance with Accounting Standards Codification 932, Extractive Activities – Oil and Gas (“ASC 932”), which requires, among other things, that “sufficient progress” be made with respect to oil and natural gas projects in order to avoid the requirement to expense previously capitalized exploratory or appraisal well costs.  Given Sonangol’s delays and failure to date to grant the extensions as well as the general investment climate in the Angolan oil and natural gas industry, the procedures of ASC 932 require us to record a full impairment of our Angolan assets.  In addition, we also recorded $62.0 million of impairment charges related to inventory and other property in Angola.  

 

In March 2017, we submitted a Notice of Dispute to Sonangol pursuant to the Sale Agreement.  We then filed a filed a Request for Arbitration (“RFA”) with the International Chamber of Commerce (“ICC”) against Sonangol for breach of the Sale Agreement.  Through this arbitration proceeding, we are requesting an award against Sonangol in excess of $2.0 billion, plus applicable interest and costs.  In July 17, 2017, Sonangol filed an Answer to our RFA and Counterclaim, asking for repayment of the $250.0 million initial payment that Sonangol made to us under the Sale Agreement.  

 

We also filed a separate RFA with the ICC against Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) seeking recovery of approximately $162.0 million in unpaid cash calls, plus applicable interest and costs, representing the joint interest receivable owed to us for operations on Block 21 offshore Angola. 

 

On December 19, 2017, certain of our subsidiaries executed a settlement agreement (the “Agreement”) with Sonangol and Sonangol P&P to resolve all disputes and transition our interests in Blocks 20 and 21 offshore Angola to Sonangol for $500.0 million. Pursuant to the Agreement, Sonangol is required to pay an initial non–refundable payment of $150.0 million on or before February 23, 2018 (the “Initial Payment”) and the final payment of $350.0 million on or before July 1, 2018 (the “Final Payment”).  On January 25, 2018, the Bankruptcy Court entered an Order Approving Debtors’ Motion for Entry of an Order (I) Authorizing Performance Under Settlement Agreement, (II) Approving Settlement Agreement, and (III) Granting Related Relief [Docket No. 127] authorizing the Debtors’ entry into the Agreement subject to the terms and conditions set forth therein.  The Agreement remains subject to the review of the Bankruptcy Court.

On February 21, 2018, we received the Initial Payment, and, in accordance with the Agreement, we (i) notified the relevant ICC arbitral tribunal of the agreement between Sonangol P&P and us to terminate the proceedings related to the joint interest receivable owed to us for operations on Block 21 offshore Angola and (ii) notified the

 

F-15

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

relevant ICC arbitral tribunal of the agreement between Sonangol and us to extend the procedural timetable by an additional four months for the proceedings related to the PSA (the “PSA Arbitration”).

 

In accordance with the Agreement, we and Sonangol are finalizing definitive documentation to implement our exit from Angola and to extinguish all debts and obligations of us and Sonangol to each other that have not already been extinguished pursuant to the Agreement.  Our claims in the PSA Arbitration will be extinguished upon our receipt of the Final Payment, which is due by July 1, 2018.  Within 48 hours of receipt of the Final Payment, we are required under the Agreement to notify the ICC arbitral tribunal in the PSA Arbitration of our agreement to terminate the proceedings related to the dispute arising from the failed Sale Agreement.  

 

NOTE 4. INVESTMENTS

 

Our investments in held–to–maturity securities consist of the following as of December 31:

 

 

 

These investments are recorded in our consolidated balance sheets as follows as of December 31:

 

 

 

NOTE 5. FAIR VALUE MEASUREMENTS

 

The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value.  Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities.  Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.  Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.

 

Recurring Basis

 

The commencement of the Chapter 11 Cases triggered the event of default provision of our embedded derivatives and the subsequent recognition of $44.4 million and $54.5 million of applicable premiums (as defined in the respective indentures) for the First Lien Notes and Second Lien Notes, respectively.  These premiums are considered to be part of the principal due for the First Lien Notes and Second Lien Notes and are included in “Liabilities subject to compromise” in our consolidated balance sheets.

 

 

F-16

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

The reconciliation of changes in the fair value of our embedded derivatives is as follows for the years ended December 31:

 

 

The following table represents the fair value hierarchy for our liabilities required to be measured at fair value on a recurring basis:

 

 

The fair values of these embedded derivatives were estimated using the “with” and “without” method.  Using this methodology, the First Lien Notes and Second Lien Notes were first valued with the embedded derivatives (the “with” scenario) and subsequently valued without the embedded derivative (the “without” scenario).  The fair values of the embedded derivatives were estimated as the difference between the fair values of the First Lien Notes and Second Lien Notes in the “with” and “without” scenarios.  The fair values of the First Lien Notes and Second Lien Notes in the “with” and “without” scenarios were estimated using a risk–neutral probability of default model. Significant Level 3 assumptions used in the valuation of the embedded derivatives were the fair values of our long–term debt, the expected recovery rates, the risk–neutral probability of default and the risk–free rates.

 

Nonrecurring Basis

 

In 2015, as a result of a reduction in future net cash flows, we recognized a $256.8 million impairment charge to write down proved oil and natural gas properties to their fair value of $68.4 million.  The fair value was determined using the income approach and was based on the expected present value of the future net cash flows from estimated reserves.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data. 

 

Financial Instruments

 

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, joint interest and other receivables, held–to–maturity investments, accounts payable and accrued liabilities. The carrying amounts of our financial instruments, other than held–to–maturity–investments and long–term debt, approximate fair value because of the short–term nature of the items.   

There were no significant unrecognized holding gains or losses related to our held–to–maturity investments as of December 31, 2016.  Accordingly, the carrying value of our held–to–maturity investments approximates their fair value.  Our held–to–maturity investments were not traded on a public exchange and the fair value of these investments was based on inputs using valuations obtained from independent brokers.  As these valuations used

 

F-17

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

readily observable market parameters that were actively quoted and could be validated through external sources, we categorized these investments as Level 2.    

 

The estimated fair value of our long–term debt is as follows as of December 31:

 

 

The fair values of our long–term debt were estimated using quoted market prices.  As these valuations use quoted prices in active markets for identical assets or liabilities, we have categorized the long–term debt as Level 1.  

 

NOTE 6. OIL AND NATURAL GAS PROPERTIES

 

Oil and natural gas properties consisted of the following as of December 31:

 

 

Capitalized Exploratory Well Costs

 

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

 

 

 

F-18

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

 

 

As of December 31, 2017, capitalized exploratory well costs that have been suspended longer than one year are associated with our Anchor and North Platte discoveries.  As of December 31, 2016, capitalized exploratory well costs that have been suspended longer than one year are associated with our Shenandoah, North Platte, Anchor, and Gabon 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.  We believe these discoveries exhibit sufficient indications of hydrocarbons to justify potential development and are 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.

 

NOTE 7. LONG–TERM DEBT, NET

 

Long–term debt, net consisted of the following as of December 31:

 

 

 

 

 

F-19

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

 

 

 

Acceleration of Debt Obligations

 

The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under all of our long–term debt obligations.  Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Cases and the holders’ rights of enforcement in respect of these debt obligations are subject to the applicable provisions of the Bankruptcy Code.

 

We are making adequate protection payments with respect to our First Lien Notes consisting of the payment of interest (at the default rate of 11.75%) and the payment of all reasonable fees and expenses of professionals retained by the holders of the First Lien Notes.  We are also making adequate protection payments with respect to our remaining long–term debt in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the debt.

 

Debt Exchanges

 

In December 2016, we consummated a debt exchange and financing transaction (the “2016 Transaction”) with certain holders (the “2016 Holders”) of our outstanding 2.625% Convertible Senior Notes due 2019 (the “2019 Notes”) and 3.125% Convertible Senior Notes due 2024 (the “2024 Notes”).  The 2016 Transaction consisted of: (i) the issuance of $500.0 million aggregate principal amount of our First Lien Notes to Holders for cash at a price of 98% and (ii) the issuance of $584.7 million aggregate principal amount of our Second Lien Notes and 30.0 million shares of our common stock to Holders in exchange for $616.6 million aggregate principal amount of 2019 Notes and $95.9 million aggregate principal amount of 2024 Notes held by the Holders.  In addition, we recognized embedded derivative liabilities of $24.8 million and $22.8 million for our First Lien Notes and Second Lien Notes, respectively.  

 

We accounted for the 2016 Transaction as a debt modification as we determined that the terms of the new debt instruments were not substantially different from the terms of the original instruments.  We did not recognize any gain or loss on the 2016 Transaction and prospectively adjusted the effective interest rates on the 2019 Notes and 2024 Notes.  Costs related to the Transaction totaled $19.6 million and are included in “General and administrative expenses” in our consolidated statements of operations.

 

In 2017, we consummated three follow–on debt exchange transactions (the “2017 Transactions”) with certain holders (the “2017 Holders”) of our outstanding 2019 Notes and 2024 Notes whereby we issued an aggregate principal amount of $350.0 million in additional Second Lien Notes in exchange for $144.3 million aggregate principal amount of the 2019 Notes and $417.2 million aggregate principal amount of the 2024 Notes held by the 2017 Holders.  In addition, we recognized additional embedded derivative liabilities of $33.1 million for our Second Lien Notes.    

 

We accounted for the 2017 Transactions as troubled debt restructurings.  We did not recognize any gain or loss on the 2017 Transactions and prospectively adjusted the effective interest rates on the 2019 Notes and 2024 Notes.  Costs related to the Transactions totaled $3.0 million and are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

10.75% First Lien Notes

 

The 10.75% First Lien Notes were issued on December 6, 2016 and mature on December 1, 2021.  Interest is payable semi–annually in arrears on each June 1 and December 1 of each year.  The First Lien Notes are initially guaranteed by all of our wholly–owned domestic subsidiaries (the “Guarantors”) and are secured, subject to certain exceptions, by a first priority lien on (i) substantially all of ours and the Guarantors’ assets and (ii) 65% of the shares

 

F-20

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

of capital stock of Cobalt International Energy Overseas Ltd., which indirectly owns our working interests in our blocks offshore Angola and offshore Gabon (collectively, the “Collateral”).

 

As of December 31, 2017, the First Lien Notes were reflected as “Liabilities subject to compromise” in our consolidated balance sheets with the carrying value equal to the face value of the notes.  The unamortized discount of $29.3 million as of the Petition Date was expensed and recognized in “Reorganization expenses” in our consolidated statement of operations.  

 

7.75% Second Lien Notes

 

The 7.75% Second Lien Notes were issued pursuant to an indenture dated December 6, 2016 (as amended or supplemented from time to time, the “Second Lien Indenture”) and mature on December 1, 2023.  Interest is payable semi–annually in arrears on each June 1 and December 1 of each year.  The Second Lien Notes are guaranteed by the Guarantors and are secured, subject to certain exceptions, by a second priority lien on the Collateral.

 

As of December 31, 2017, the Second Lien Notes were reflected as “Liabilities subject to compromise” in our consolidated balance sheets with the carrying value equal to the face value of the notes.  The unamortized discount of $19.4 million as of the Petition Date was expensed and recognized in “Reorganization expenses” in our consolidated statement of operations.  In addition, $2.6 million of accrued but unpaid interest is reflected as “Liabilities subject to compromise” in our consolidated balance sheets.  We have not recognized any interest expense on our Second Lien Notes subsequent to the Petition Date.  Unrecognized contractual interest expense on our Second Lien Notes for 2017 was $3.4 million.  

 

2.625% Convertible Senior Notes due 2019

 

The 2019 Notes were issued under an indenture dated December 17, 2012 (the “2019 Indenture”) and mature December 1, 2019.  Interest is payable semi–annually in arrears on June 1 and December 1 of each year.  The 2019 Notes are senior unsecured obligations.

 

The 2019 Notes may be converted at the option of the holder on the second scheduled trading day immediately preceding the maturity date, in multiples of $1,000 principal amount. The 2019 Notes are convertible at an initial conversion rate of 1.8682 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $535.20 per share. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in 2019 Indenture, but will not be adjusted for any accrued and unpaid interest except in limited circumstances.  We can satisfy the conversion obligation, at our option, in either cash, shares of common stock or a combination thereof.

 

When the 2019 Notes were issued, we accounted for the debt and equity components of the 2019 Notes separately, as we have the option to settle the conversion obligation in cash.  At the date of issuance, we calculated the fair value of the 2019 Notes, excluding the conversion feature, based on the fair value of similar non–convertible debt instruments.  The difference between the cash proceeds and the estimated fair value represented the value which was assigned to the equity component and recorded as a debt discount.  Prior to the Petition Date, the debt discount was being amortized using the effective interest rate method over the period from issuance to the maturity date of December 1, 2019.  The carrying amount of the equity component of the 2019 Notes reported in additional paid in capital was initially valued at $381.4 million, which was net of $9.1 million of debt issuance costs allocated to the equity component.

 

As the closing price of our common stock on December 31, 2017 was less than the initial conversion price for the 2019 Notes, the if–converted value of the 2019 Notes would be less than principal amount.  

 

Holders of the 2019 Notes who convert their notes in connection with a “make–whole fundamental change”, as defined in the 2019 Indenture, 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 2019 Indenture, holders of the 2019 Notes may require us to repurchase for cash all or a portion of their notes equal to $1,000, or a multiple of

 

F-21

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

$1,000, at a fundamental change repurchase price equal to 100% of the principal amount of 2019 Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date.

As of December 31, 2017, the 2019 Notes were reflected as “Liabilities subject to compromise” in our consolidated balance sheets with the carrying value equal to the face value of the notes.  The unamortized discount and debt issuance costs of $58.3 million and $3.9 million, respectively, as of the Petition Date was expensed and recognized in “Reorganization expenses” in our consolidated statement of operations.  

 

On December 1, 2017, we elected to defer the $8.1 million interest payment that was due on December 1, 2017.  As of consequence of the commencement of the Chapter 11 Cases, such interest payment has not been made, and is classified as “Liabilities subject to compromise” in our consolidated balance sheets.  In addition, $8.7 million of accrued but unpaid interest from December 1, 2017 through December 13, 2017 is reflected as “Liabilities subject to compromise” in our consolidated balance sheets.  We have not recognized any interest expense on our 2019 Notes subsequent to the Petition Date.  Unrecognized contractual interest expense on our 2019 Notes for 2017 was $0.8 million.  

 

3.125% Convertible Senior Notes due 2024

 

The 2024 Notes were issued under an indenture dated May 13, 2014 (the “2024 Indenture”) and mature on May 15, 2024.  Interest is payable semi–annually in arrears on May 15 and November 15 of each year.  The 2024 Notes are senior unsecured obligations and ran equal in right of payment to the 2019 Notes.  

 

Prior to November 15, 2023, the 3.125% Notes are convertible only under certain circumstances as outlined in the 2024 Indenture.  On or after November 15, 2023, the 2024 Notes may be converted at the option of the holder at any time on the second scheduled trading day immediately preceding the stated maturity date, in multiples of $1,000 principal amount.

 

The 2024 Notes are convertible at an initial conversion rate of 2.8907 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $345.90 per share. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in the 2024 Indenture, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. We can satisfy the conversion obligation, at our option, in either cash, shares of common stock or a combination thereof.

 

When the 2024 Notes were issued, we accounted for the debt and equity components of the 2024 Notes separately, as we have the option to settle the conversion obligation in cash.  At the date of issuance, we calculated the fair value of the 2024 Notes, excluding the conversion feature, based on the fair value of similar non–convertible debt instruments.  The difference between the cash proceeds and the estimated fair value represented the value which was assigned to the equity component and recorded as a debt discount.  Prior to the Petition Date, the debt discount was being amortized using the effective interest rate method over the period from issuance to the maturity date of May 15, 2024.  The carrying amount of the equity component of the 2024 Notes reported in additional paid in capital was initially valued at $464.7 million, which was net of $11.1 million of debt issuance costs allocated to the equity component.

 

As the closing price of our common stock on December 31, 2017 was less than the initial conversion price for the 2024 Notes, the if–converted value of the 2024 Notes would be less than principal amount.  

 

Holders of the 2024 Notes who convert their notes in connection with a “make– whole fundamental change”, as defined in the 2024 Indenture, 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 2024 Indenture, holders of the 2024 Notes may require us 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 2024 Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date.

 

As of December 31, 2017, the 2024 Notes were reflected as “Liabilities subject to compromise” in our consolidated balance sheets with the carrying value equal to the face value of the notes.  The unamortized discount

 

F-22

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

and debt issuance costs of $211.5 million and $9.4 million, respectively, as of the Petition Date was expensed and recognized in “Reorganization expenses” in our consolidated statement of operations.  

 

On November 15, 2017, we elected to defer the $12.3 million interest payment that was due on November 15, 2017.  As of consequence of the commencement of the Chapter 11 Cases, such interest payment has not been made, and is classified as “Liabilities subject to compromise” in our consolidated balance sheets.  In addition, $14.2 million of accrued but unpaid interest from November 15, 2017 through December 13, 2017 is reflected as “Liabilities subject to compromise” in our consolidated balance sheets.  We have not recognized any interest expense on our 2024 Notes subsequent to the Petition Date.  Unrecognized contractual interest expense on our 2024 Notes for 2017 was $1.2 million.  

 

Borrowing Base Facility Agreement

 

In 2015, Cobalt GOM #1 LLC, an indirect, wholly-owned subsidiary, entered into a Borrowing Base Facility Agreement (the “Facility Agreement”) which provided for a limited recourse $150.0 million senior secured reserve–based term loan facility, with an amount available for borrowing at any time limited to a periodically adjusted borrowing base amount.    

 

In 2016, we terminated the Facility Agreement because 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.  In conjunction with the termination, we wrote off $3.3 million of debt issuance costs associated with the facility agreement.  

 

We had no amounts outstanding under the Facility Agreement at any time it was in place.

 

Maturities of Long–Term Debt

 

The maturities of our long–term debt are as follows for the years ended December 31:

 

 

NOTE 8. ASSET RETIREMENT OBLIGATIONS

 

The changes in ARO are as follows for the years ended December 31:

 

 

NOTE 9. COMMITMENTS AND CONTINGENCIES

 

We are currently, and from time to time we may become, involved in various legal and regulatory proceedings arising in the normal course of business.

 

In November 2014, two purported stockholders, St. Lucie County Fire District Firefighters’ Pension Trust Fund and Fire and Police Retiree Health Care Fund, San Antonio, filed a class action lawsuit in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through November 4, 2014 (the “St. Lucie lawsuit”). The St. Lucie lawsuit, filed against us and certain officers, former and current members of the Board of Directors, underwriters, and investment firms and funds,

 

F-23

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures, primarily regarding compliance with the U.S. Foreign Corrupt Practices Act (“FCPA”) in our Angolan operations and the performance of certain wells offshore Angola.

 

In December 2014, Steven Neuman, a purported stockholder, filed a substantially similar lawsuit against us and certain of our officers in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through August 4, 2014 (the “Neuman lawsuit”). Like the St. Lucie lawsuit, the Neuman lawsuit asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding our compliance with the FCPA in our Angolan operations.

 

In March 2015, the Court entered an order consolidating the Neuman lawsuit with the St. Lucie lawsuit (the “Consolidated Action”) and also entered an order in the Consolidated Action appointing Lead Plaintiffs and Lead Counsel. Lead Plaintiffs filed their consolidated amended complaint in May 2015. Among other remedies, the Consolidated Action seeks damages in an unspecified amount, along with an award of attorney fees and other costs and expenses to the plaintiffs. We filed a motion to dismiss the consolidated amended complaint in June 2015, and the other defendants also filed motions to dismiss. The Court denied our motion to dismiss in January 2016, and, in March 2016, the Court also denied our motion requesting that the Court certify its order on the motions to dismiss so that we may seek interlocutory appellate review of the order.   In June 2017, the Court certified a class of all persons and entities who purchased or otherwise acquired our securities between March 1, 2011 and November 3, 2014.  In July 2017, we filed a petition for permission to file an interlocutory appeal challenging the class certification order.  On August 4, 2017, the Fifth Circuit Court of Appeals granted our petition for permission to file the interlocutory appeal.  We filed our appeal on October 10, 2017 and briefing is now complete.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy and the Court stayed the Consolidated Action the following day.  The court presiding over our bankruptcy proceeding subsequently entered an order staying the Consolidated Proceeding in its entirety through April 20, 2018.  On December 22, 2017, Plaintiffs moved to dismiss Cobalt from the Consolidated Action.  The Court denied the motion without prejudice on January 24, 2018, holding that the Plaintiffs could reurge their motion 31 days after providing notice and an opportunity to object to class members via publication in Business Wire.  

 

In May 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.  In July 2016, we filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us.  The Court heard arguments on our special exceptions in December 2016.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy. The matter remains ongoing.

 

In November 2016, McDonaugh, a purported stockholder, filed a derivative action in the 80th District Court in Harris County, Texas against us, as a nominal defendant, and certain of our current and former officers and directors.  The lawsuit alleges that defendants breached their fiduciary duties by failing to maintain adequate internal controls and by permitting or failing to prevent alleged misrepresentations and omissions in our SEC filings and other public disclosures, including in relation to compliance with the FCPA in our Angolan operations and regarding the performance of certain wells offshore Angola.  The lawsuit also alleges that defendants received compensation or other benefits in excess of what they were entitled and that certain officers and directors engaged in unlawful trading and misappropriation of information.  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, reform of our governance and internal controls, restitution and disgorgement of profits, and an award of attorney fees and other costs and expenses.  We filed our answer and special exceptions challenging the plaintiff’s

 

F-24

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

standing to bring such claims against us in January 2017.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy.  The matter remains ongoing.

 

In April 2017, Hafkey, a purported stockholder, filed a derivative action in the 295th District Court in Harris County, Texas against us, as a nominal defendant, and certain of our current and former officers and directors.  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 exploratory wells offshore Angola; that certain directors caused us to waste corporate assets; and that certain officers received performance–based compensation in excess of what they were entitled. The lawsuit further alleges that demand was wrongfully refused.  The plaintiff asserts claims for breach of fiduciary duty, corporate waste, 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.  We filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us in June 2017.  On December 14, 2017, we filed a notice of suggestion on pendency of bankruptcy.  The matter remains ongoing.

 

We are vigorously defending against the current derivatives lawsuits and do not believe they will have a material adverse effect on our business. However, we cannot predict the occurrence or outcome of these proceedings with certainty, and if we are unsuccessful in these litigations and any loss exceeds our available insurance, this could have a material adverse effect on our results of operations.

 

In May 2016, we filed suit against XL in Harris County District Court in Houston, Texas.  We asserted XL improperly denied coverage for insurance claims made in July 2012 and other claims subsequently submitted to them in connection with our defending against the St. Lucie lawsuit and other investigations and actions.   In December 2016, we amended our petition to add Axis, as Axis provided coverage in excess of the XL policy’s limit of liability.  We alleged breach of contract, violation of the Texas Prompt Payment of Claims Act, and sought a declaratory judgment that XL and Axis were obligated to pay any additional loss suffered by us due to the circumstances, investigation, and claims described in the suit.  In December 2016, we also amended our petition to add claims against Illinois National Insurance Company, an AIG subsidiary (“AIG”), which served as our insurer after XL.  Against AIG, we allege breach of contract, violation of the Texas Prompt Payment of Claims Act, violation of the Texas Deceptive Trade Practices-Consumer Protection Act, and seek a declaratory judgment that AIG is obligated to pay any additional loss suffered by us due to the circumstances, investigations, and actions related to the Lontra and/or Loengo wells.  In April 2017, we and certain of our current and former officers and directors (the “Intervenors”) settled claims against XL pursuant to which XL paid $11.5 million.  In October 2017, we and the Intervenors settled claims against Axis pursuant to which Axis has agreed to pay $6.65 million. We continue to pursue our claims against AIG.

 

The settlement proceeds from XL and Axis are included in “Other income” in our consolidated statements of operations for 2017.  Of the $18.2 million, $15.4 million is being held in escrow for the benefit of the insured persons under the XL policy.  This restricted cash is included in “Other assets” in our consolidated balance sheets.    

 

At December 31, 2017, we had the following estimated contractual commitments for the years ending December 31:

 

  

 

F-25

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

 

 

We recorded $6.2million, $9.2 million, and $12.4 million of office and delay rental expense in 2017, 2016 and 2015, respectively.

 

NOTE 10. EQUITY–BASED COMPENSATION

 

We have various long–term incentive plans for employees.  These plans allow for the issuance of restricted stock awards (“RSAs”), non–qualified stock options (“NQSOs”), performance stock units (“PSUs”), stock appreciation rights (“SARs”) and restricted stock units (“RSUs”).  As of December 31, 2017, we have 1.7 million shares authorized for issuance under these plans, and 0.7 million shares remain available for grant.

 

We also have various long–term incentive plans for our non–employee directors.  These plans allow for the issuance of NQSOs, RSUs or other equity–based awards as retainers.  As of December 31, 2017, we have 0.3 million shares authorized for issuance under these plans, and 0.2 million shares remain available for grant.  

 

Our policy is to issue new shares when RSAs are granted, when NQSOs are exercised and, should we elect to settle our PSUs, SARs and RSUs in shares of our common stock, when PSUs, SARs and RSUs are vested.

 

Restricted Stock Awards    

 

An RSA is an award of common stock with no exercise price.  For RSAs with both a performance and a service condition, we estimated the fair value using the Monte Carlo simulation model.  For RSAs with a service condition only, we estimated the fair value using the market price of our common stock on the grant date.  RSAs generally vest in three equal annual installments.  

 

The following weighted average assumptions were used to estimate the fair value of the RSAs for the year ended December 31:

 

 

Volatility was estimated based on historical daily prices from January 1, 2010 to the grant date.  The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the RSAs contractual term.  The expected dividend yield was not taken into account as we have historically not paid any dividends.  The expected life was based on the derived service period, which is the period between the grant date and the date the performance condition is met, as calculated by the Monte Carlo simulation model.  

 

 

F-26

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Activity related to RSAs is as follows:

 

 

The fair value of RSAs granted in 2016 and 2015 was $6.3 million and $30.5 million, respectively, and the fair value of RSAs vested in 2017, 2016 and 2015 was $13.3 million, $4.6 million and $1.4 million, respectively.

 

The weighted average remaining contractual terms for RSAs outstanding and RSAs exercisable at December 31, 2017 were 5.3 years and 4.9 years, respectively.  

 

As of December 31, 2017, there was $4.4 million of total unrecognized compensation cost related to unvested RSAs which is expected to be recognized over a weighted-average period of 1.1 years.

 

Non-Qualified Stock Options

 

We grant NQSOs to employees at an exercise price equal to the market value of our common stock on the grant date.  The NQSOs have contractual terms of 10 years.  We did not grant any NQSOs in 2017.  The NQSOs granted in 2016 and 2015 vest after one year of service, subject to our common stock maintaining a minimum stock price for a specified period of time.  

 

As the NQSOs granted in 2016 and 2015 had both service and market conditions, we estimated the fair value of these NQSOs using the Monte Carlo simulation model.  The following weighted average assumptions were used to estimate the fair value of the NQSOs for the years ended December 31:

 

 

Volatility was estimated based on historical daily prices from January 1, 2010 to the grant date.  The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the NQSOs contractual term.  The expected dividend yield was not taken into account as we have historically not paid any dividends.  The expected life was based on the derived service period, which is the period between the grant date and the date the performance condition is met, as calculated by the Monte Carlo simulation model.  

 

As of both December 31, 2017 and 2016, we had 0.3 million NQSOs outstanding and exercisable with a weighted average exercise price of $199.28.  No NQSOs were granted or forfeited in 2017.   

 

The fair value of NQSOs granted in 2016 and 2015 was $4.0 million and $5.9 million, respectively, and the fair value of NQSOs vested in 2017, 2016 and 2015 was $2.7 million, $14.5 million and $12.3 million, respectively.  

 

The weighted average remaining contractual term for both NQSOs outstanding and NQSOs exercisable at December 31, 2017 was 5.7 years.  There was no intrinsic value for both NQSOs outstanding and NQSOs exercisable as the exercise price exceeded the market price of our common stock as of December 31, 2017.

 

F-27

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Performance Stock Units

 

A PSU is an award where each unit represents the right to receive, subject to our common stock attaining a specified return, the value of one share of our common stock at the date of vesting.  The PSUs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise.  The PSUs vest in three equal installments subject to our common stock attaining a specified return each vesting date.  We estimated the fair value of the PSUs using the Monte Carlo simulation model as the PSUs have both service and performance conditions.  

 

The following weighted average assumptions were used to estimate the fair value of the PSUs for the year ended December 31:

 

 

Expected volatility was calculated for the peer company based on historical volatility over the most recent three years using daily stock prices.  The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the end date of the longest remaining period of three years.  The expected dividend yield was not taken into account as we have historically not paid any dividends.  

Activity related to the PSUs is as follows:

 

 

The fair value of PSUs granted in 2017 and 2016 was $4.3 million and $0.2 million, respectively.

 

The weighted average remaining contractual term for PSUs outstanding at December 31, 2016 was 8.8 years.

 

As of December 31, 2017, there was $0.3 million of total unrecognized compensation cost related to unvested PSUs which is expected to be recognized over a weighted-average period of 2.2 years.

 

Restricted Stock Units

 

An RSU is an award where each unit represents the right to receive the value of one share of our common stock at the date of vesting.  RSUs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise.  The RSUs vest in three equal annual installments.  

 

 

F-28

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Activity related to the RSUs is as follows:

 

 

The fair value of RSUs granted in 2017 and 2016 was $7.5 million and $8.5 million, respectively.  No RSUs were granted in 2015.  The fair value of RSUs vested in 2017 and 2016 was $2.3 million and $0.8 million.  No RSUs vested in 2015.  

 

The weighted average remaining contractual terms for RSUs outstanding and RSUs exercisable at December 31, 2017 was 8.9 years and 8.1 years, respectively.

 

As of December 31, 2017, there was $4.3 million of total unrecognized compensation cost related to unvested RSUs which is expected to be recognized over a weighted–average period of 1.8 years.

 

Stock Appreciation Rights

 

An SAR represents a contractual right to receive an amount equal to the appreciation in the price of one share of our common stock from the grant date over the exercise price of the SAR.  SARs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise.  We grant SARs to employees at an exercise price equal to the market value of our common stock on the grant date.  The SARs have contractual terms of 10 years and vest in three equal annual installments.  

 

We account for the SARs as liability awards, and the fair value of the SARs is remeasured at the end of each reporting period based on the current fair value of the SARs.  We estimate the fair value of the SARs using the Black–Scholes option price model.  

 

The following weighted average assumptions were used to estimate the fair value of the SARs for the year ended December 31:  

 

 

As of both December 31, 2017 and 2016, we had 0.1 million SARs outstanding and exercisable with a weighted average exercise price of $133.05.   No SARs were granted or forfeited in 2017.  

The weighted average grant date fair value of SARs granted in 2015 was $4.2 million.  No SARs were granted in 2017 or 2016.

 

 

F-29

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

As of December 31, 2017, the weighted average remaining contractual term for both SARs outstanding and SARs exercisable was 7.2 years and there was no intrinsic value for both the SARS outstanding and the SARS exercisable as the exercise price exceeds the market price of our common stock as of December 31, 2017.

 

Non–Employee Director Grants

 

We granted a total of 0.1 million, 0.02 million and 3 thousand shares of our common stock to our non–employee directors as retainer awards in 2017, 2016 and 2015, respectively.  The directors have elected to defer the issuance of this stock.  Accordingly, we have recorded a liability for the future issuance of these shares.  The weighted average fair value of the common stock granted in 2017, 2016 and 2015 was $3.62, $28.34 and $128.97, respectively.

 

In addition, we granted 0.1 million and 0.02 million RSUs to our non–employee directors in 2017 and 2016, respectively.  These RSUs will be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof.  The fair value of these RSUs granted in 2017 and 2016 was $1.5 million and $0.8 million, respectively.    

 

Settlement of Equity–Based Awards

 

In August 2017, we entered in retention agreements with certain of our officers (see Note 15).  Included in these agreements were payments totaling $12.2 million for the repurchase of certain PSUs and RSUs (collectively, the “Awards”) that had been issued to these officers in February 2017.  Each of the payments is subject to clawback and repayment by the applicable officer in the event such officer is terminated with cause or resigns without good reason before the one–year anniversary of the agreement.  The repurchase of the Awards was accounted for as a modification of the original Awards with a revised service period of 18 months (date of grant through the end of the clawback period).

As the Awards were not vested as of the repurchase date, we recognized $9.8 million of equity compensation cost in 2017.  This amount corresponds to the percentage of the service period that had been rendered prior to the modification date.  The remainder of the equity compensation cost will be recognized over the remaining service period of the Awards.  

 

Compensation Cost

 

Equity–based compensation cost is measured at the date of grant based on the calculated fair value of the award and is generally recognized on a straight–line basis over the requisite service period, including those with graded vesting.  The compensation cost is determined based on awards ultimately expected to vest, and we have reduced the cost for estimated forfeitures based on historical forfeiture rtes.  Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures.  

 

The following table presents the compensation costs recognized for the years ended December 31:

 

 

NOTE 11. EMPLOYEE BENEFIT PLAN

 

We have a defined contribution 401(k) plan (the “Plan”).  All of our employees are eligible to participate in the Plan after three months of continuous employment.  The plan is discretionary and provides a 6% employee contribution match as determined by our Board of Directors. For 2017, 2016 and 2015, we recorded $1.0 million, $1.5 million and $1.7 million, respectively, in benefits contributions to the Plan, which are included in general and administrative expenses in our consolidated statements of operations.

 

F-30

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

 

NOTE 12. INCOME TAXES

 

The provision for income taxes is comprised of the following for the years ended December 31:

 

 

As we establish full valuation allowances against net deferred tax assets where we have determined that it is more likely than not that all of the deferred tax assets will not be realized, we have recognized no income taxes in our consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015.

 

The geographic sources of our loss are as follows for the years ended December 31:

 

 

The effective tax rate on our loss differs from the U.S. statutory rate as follows for the years ended December 31:

 

 

On December 22, 2017, the Tax Cut and Jobs Act (the “Act”) was enacted into law.  Many of the provisions of the Act are effective beginning January 1, 2018, most notable of which is the reduction in the federal corporate statutory rate from 35% to 21%.  The changes included in the Act are broad and complex.  We are currently in the process of finalizing and quantifying the tax effects of the Act, but have recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the Act in our consolidated financial statements for 2017.  The final transition impacts of the Act may differ from the estimate above due to, among other things, changes in interpretations of the Act, any legislative action to address questions that arise because of the Act, any changes in accounting standards for income taxes or related interpretations in response to the Act, or any updates or changes to estimates we have utilized to calculate the transition impacts.  The SEC has issued rules that would allow for a measurement period of up to one year after the enactment date of the Act to finalize the recording of the relates tax impacts.

 

 

F-31

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.  The tax effects of our temporary differences and net operating losses (“NOL”) are as follows at December 31:

 

 

As of December 31, 2017, we had NOL carryforwards for federal and state income tax purposes of approximately $2,273.0 million and $73.3 million, respectively, which begin to expire in 2026 and 2025, respectively.

 

As of December 31, 2017, we had an NOL carryforward for foreign income tax purposes of approximately $51.3 million which began to expire in 2016.  

 

The utilization of the NOL carryforwards is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period.  

 

Under the U.S. Internal Revenue Code, our ability to use our NOL carryforwards and other tax attributes may be limited if we experience a change of control, as determined under U.S. Internal Revenue Code.  Accordingly, we obtained an order from the Bankruptcy Court that is intended to protect our ability to use our tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our common stock.

 

In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of our common stock.  Such persons are required to notify us and the Bankruptcy Court before effecting a transaction that might result in us losing the ability to use our tax attributes, and we have the right to seek an injunction to prevent the transaction if it might adversely affect our ability to use our tax attributes.  

 

Any purchase, sale or other transfer of our equity securities in violation of the restrictions of the order is null and would be treated as invalid from the outset as an act in violation of a Bankruptcy Court order and would therefore confer no rights on a proposed transferee.

 

Our tax filings are subject to examination by federal and state tax authorities where we conduct our business. These examinations may result in assessments of additional tax that are resolved with the authorities or through the courts. We have evaluated whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions we have taken are supportable by existing laws and related interpretations, we believe there are no material uncertain tax positions to consider.  There were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits as of December 31, 2017 and 2016.

 

 

F-32

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

NOTE 13. EARNINGS PER SHARE

 

A reconciliation of the number of shares used for the basic and diluted loss per share computations is as follows for the years ended December 31:

 

 

 

NOTE 14. OTHER SUPPLEMENTAL INFORMATION

 

Cash, cash equivalents and restricted cash are recorded in our consolidated balance sheets as follows as of December 31:

 

 

Supplemental cash flows and noncash transactions were as follows as of and for the years ended December 31:

 

 

Accrued liabilities consisted of the following as of December 31:

 

 

 

F-33

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

NOTE 15.  OTHER MATTERS

 

In September 2016, we announced that we entered into an amendment to our drilling contract with Rowan (UK) Reliance Limited and recorded a charge of $95.9 million, of which $76.3 million was paid in 2016 and $19.6 million was paid in 2017.  This amendment provided for the early termination of our long–term drilling contract for one of their drillships.  The drilling contract was originally scheduled to terminate in February 2018, but the amendment provides for a contract termination date in March 2017.  This charge is recorded in “Loss on amendment of contract” in our consolidated statements of operations.  

 

On March 13, 2017, the SEC informed us that it had initiated an informal inquiry regarding the Sonangol Research and Technology Center (the “SRTC”).  As background, in December 2011, we executed the PSC under which we and BP are required to make certain social contributions to Sonangol, including for the SRTC.  In March 13, 2017, we also received from the SEC a voluntary request for information regarding such inquiry.  We cooperated with the SEC, providing requested information regarding the SRTC.  The SEC also asked for, and we provided, information regarding other aspects of our Angolan operations, including two of our wells offshore Angola.  On January 29, 2018, the SEC formally concluded its investigation into potential violations of the federal securities laws, including the Foreign Corrupt Practices Act, and advised that the SEC staff did not intend to recommend any enforcement action by the SEC against us.

 

In 2017, we entered into retention agreements with certain of our officers and employees.  The retention agreements provided for one–time lump sum payments totaling $19.7 million.  Of this amount, $12.2 million was paid to certain officers for the repurchase of the Awards (see Note 10) and $7.5 million was paid as retention bonuses to certain employees.  Each of the payments is subject to clawback and repayment by the applicable officer and employee in the event such officer or employee is terminated with cause or resigns without good reason before the one–year anniversary of the agreement.  As of December 31, 2017, $11.6 million of these payments, consisting of equity compensation costs of $7.0 million (see Note 10) and compensation expense of $4.6 million, are included in “Other current assets” in our unaudited condensed consolidated balance sheets and will be recognized over the remaining service period.  In 2017, $13.4 million of these payments are included in “General and administrative expenses” in our consolidated statements of operations.

 

NOTE 16. QUARTERLY DATA (UNAUDITED)

 

 

 

 

 

 

F-34

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

NOTE 17. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)

 

Oil and Natural Gas Properties

 

Capitalized costs relating to oil and natural gas producing activities are as follows at December 31:

 

 

Costs incurred in oil and natural gas property development activities are as follows for the years ended December 31:

 

 

Estimated Proved Oil, Natural Gas and Natural Gas Liquids Reserves

 

Our estimated proved reserves are all located within the U.S. Gulf of Mexico.   We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and natural gas liquids reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates. The estimates of our proved reserves as of December 31, 2017, 2016 and 2015 have been prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum consultants.

 

 

F-35

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Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.

 

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

 

The following tables present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves.  In computing this data, assumptions other than those required by the Securities and Exchange Commission (“SEC”) could produce different results.  Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves. The following assumptions have been made:

 

F-36

---

Cobalt International Energy, Inc.

(Debtors–in–Possession)

Notes to Consolidated Financial Statements (continued)

 

The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is as follows at December 31:

 

 

As specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were the average prices during the year determined using the price of the first day of each month, except for volumes subject to fixed price contracts.  The prices utilized in calculating our total estimated proved reserves at December 31, 2017, 2016 and 2015 were $51.04, $40.32 and $50.78 per barrel of oil, $31.68, $19.23 and $15.23 per barrel of natural gas liquids, and $2.284, $2.056 and $(0.182) per Mcf of natural gas, respectively.

 

The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31:

 

 

NOTE 18. SUBSEQUENT EVENTS (UNAUDITED)

 

On February 21, 2018, we received the Initial Payment from Sonangol (see Note 3) and (i) notified the relevant ICC arbitral tribunal of the agreement between us and Sonangol to terminate the proceedings related to the joint interest receivable owed to us for operations on Block 21 offshore Angola and (ii) notified the relevant ICC arbitral tribunal of the agreement between us and Sonangol to extend the procedural timetable by an additional four months for the proceedings related to the PSA Arbitration.  In accordance with the Agreement, we and Sonangol are finalizing definitive documentation to implement our exit from Angola and to extinguish all debts and obligations of us and Sonangol to each other that have not already been extinguished pursuant to the Agreement.  Our claims in the PSA Arbitration will be extinguished upon our receipt of the Final Payment, which is due by July 1, 2018.

 

We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued and determined that there were no other material items that required recognition or disclosure in our consolidated financial statements.

 

 

 

F-37