10-K 1 cie-10k_20161231.htm CIE-10K-20161231 cie-10k_20161231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

(Mark One)

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

For the fiscal year ended December 31, 2016

OR

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

For the transition period from              to             

Commission File Number 001-34579

 

Cobalt International Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

 

27-0821169

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

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:

 

 

Title of Each Class

 

 

 

Name of Each Exchange on Which Registered

 

Common stock, $0.01 par value

 

The New York Stock Exchange

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

(Check one):

Large accelerated filer

 

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

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

As of June 30, 2016, 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 $486.6 million.

As of January 31, 2017, the registrant had 447,296,474 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement relating to the 2017 Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Annual Report on Form 10–K.

 

 

 

 

 

 


Cobalt International Energy, Inc. 

 

Item No.

 

 

 

Page No.

 

 

PART I

 

 

1

 

Business

 

5

1A

 

Risk Factors

 

31

1B

 

Unresolved Staff Comments

 

58

2

 

Properties

 

58

3

 

Legal Proceedings

 

58

4

 

Mine Safety Disclosures

 

59

 

 

PART II

 

 

5

 

Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

60

6

 

Selected Financial Data

 

62

7

 

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

 

63

7A

 

Quantitative and Qualitative Disclosures About Market Risk

 

73

8

 

Financial Statements and Supplementary Data

 

73

9

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

73

9A

 

Controls and Procedures

 

73

9B

 

Other Information

 

74

 

 

PART III

 

 

10

 

Directors, Executive Officers and Corporate Governance

 

74

11

 

Executive Compensation

 

74

12

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

75

13

 

Certain Relationships and Related Transactions, and Director Independence

 

75

14

 

Principal Accounting Fees and Services

 

75

 

 

Glossary of Oil and Natural Gas Terms

 

76

 

 

PART IV

 

 

15

 

Exhibits and Financial Statement Schedules

 

80

16

 

Form 10-K Summary

 

84

 

 

Signatures

 

85

 

 

 

 


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, and Section 21E of 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:

 

 

our liquidity and ability to finance our exploration, appraisal, development, and acquisition activities and continue as a going concern;

 

 

the availability and cost of financing, and refinancing, our indebtedness;

 

 

the financial and operational implications of the termination of the purchase and sale agreement with Sociedade Nacional de Combustiveis de Angola–Empresa Publica for the sale of our working interest in Blocks 20 and 21 offshore Angola;

 

 

our ability to sell our interests in Blocks 20 and 21 offshore Angola, U.S. Gulf of Mexico or other assets on acceptable terms;

 

 

our ability to evaluate and execute upon potential strategic alternatives and initiatives to improve liquidity;

 

 

our ability to meet our obligations under the agreements governing our current or any future indebtedness;

 

 

volatility and extended depression of oil and natural gas prices;

 

 

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

 

 

projected and targeted capital expenditures and other costs and commitments;

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

our and our partners’ ability to obtain permits to drill and develop our properties;

 

 

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

 

 


 

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

 

 

our ability to find, acquire or gain access to new prospects;

 

 

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

 

 

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

 

 

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

 

 

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

 

 

the cost and availability of adequate insurance coverage, and the ability to collect under our insurance policies;

 

 

the results or outcome of any legal proceedings or investigations;

 

our ability to maintain the listing of our common stock on the New York Stock Exchange or another national securities exchange; and

 

other risk factors discussed in the “Risk Factors” section of this Annual Report on Form 10–K.

 

The words “anticipate,” “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “intend,” “could,” “expect,” “plan” 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.

 

 

 

 


 

PART I

ITEM 1.

BUSINESS

 

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. In the U.S. Gulf of Mexico, we have four discoveries: North Platte, Shenandoah, Anchor and Heidelberg. Heidelberg began initial production in January 2016 and North Platte, Shenandoah and Anchor are currently in various stages of appraisal.  In West Africa, we have made seven aggregate discoveries offshore Angola on Blocks 20 (Orca, Zalophus, Golfinho and Lontra) and 21 (Cameia, Bicuar and Mavinga). We also have a non–operated interest in the Diaba block offshore Gabon.

 

U.S. Gulf of Mexico

 

Production and Development

 

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 27,000 BOE per day gross from five wells (the fifth production well was completed in early 2017).  As of December 31, 2016, our share of the Heidelberg field had estimated net proved reserves of 3.0 MMBbls of oil, 1.2 Bcf of natural gas and 0.1 MMBbls of natural gas liquids, or 3.3 MMBOE, and a standardized measure of $39.0 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.  

 

Appraisal and Development  

 

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 2012, we announced the North Platte discovery well encountered over 550 net feet of oil pay in multiple high quality Inboard Lower Tertiary reservoirs. In 2015, we completed drilling the initial appraisal well on North Platte, which also encountered over 550 feet of net oil pay. A subsequent sidetrack to this appraisal well was also successful.  In January 2017, we announced the completion of a second appraisal well, North Platte #4. This well encountered approximately 650 feet of net oil pay and results indicate high quality Inboard Lower Tertiary Wilcox reservoirs on the eastern flank of the North Platte field.  We recently completed the drilling of the North Platte #4 sidetrack well to further analyze the extent of the eastern flank of the North Platte field.  The well encountered oil and has confirmed that reservoir quality sands are present across the entirety of the eastern flank.  We are commencing a final sidetrack with the intention of gathering conventional core and fluid samples and expect to complete these operations in the second quarter of 2017.  Reservoir characterization, fluid analysis and modeling studies are ongoing to better understand reservoir continuity, productivity and potential resource range in order to optimize the development of the North Platte field.  In addition, we are conducting feasibility studies to evaluate varying development concepts to maximize value while attempting to minimize risk.    

 

The primary term in certain leases covering North Platte expired in late 2016 but we continue to hold these leases by conducting continuous operations in the North Platte Unit.  This means that we cannot discontinue operations at North Platte for more than 180 days or such leases will terminate unless we apply for and are granted a Suspension of Production (“SOP”).  We intend to file for an SOP upon the completion of the current North Platte #4 sidetrack.

 

 

5


 

Shenandoah  

 

The Shenandoah field is located approximately 170 miles south of Port Fourchon off the Louisiana coast in 5,800 feet of water in the Walker Ridge area. Anadarko is the operator, and we own a 20% working interest.

 

In 2009, the Shenandoah discovery well was drilled into Inboard Lower Tertiary reservoirs and encountered net oil pay approaching 300 feet. This well, located in approximately 5,750 feet of water in Walker Ridge Block 52, was drilled to approximately 30,000 feet.  We since have drilled several appraisal wells on Shenandoah. The Shenandoah #2 appraisal well was spud in 2012 and encountered more than 1,000 net feet of oil pay in multiple high quality Inboard Lower Tertiary reservoirs. The Shenandoah #3 appraisal well was spud in 2014 and evaluated the same well–developed reservoir sands 1,500 feet down–dip and 2.3 miles east of the first appraisal well.  The Shenandoah #4 appraisal well was drilled in 2015 and tested the updip extent of the basin. The subsequent Shenandoah #4 sidetrack encountered over 600 feet of net oil pay, extending the lowest known oil column downdip. In 2016, Shenandoah #5 was drilled to a total depth of 31,000 feet and encountered more than 1,000 feet of net pay in multiple Inboard Lower Tertiary sands.  Approximately 80 feet of conventional core was acquired in the upper Wilcox pay interval.  Finally, Shenandoah #6 was spud in late 2016 and encountered water.  We are currently sidetracking this well.

 

The primary terms in certain leases covering our Shenandoah Unit expired in 2014 but are being held by continuous operations.  We do not expect the operator to file for approval of an SOP.  Unless they do so, we will be required to conduct another operation to perpetuate the acreage within 180 days of the completion of the Shenandoah #6 operations.

 

Anchor  

 

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

 

The initial Anchor exploratory well was drilled in 2014 to a total depth of approximately 33,700 feet and encountered 690 feet of net oil pay in multiple Inboard Lower Tertiary reservoirs.  In 2015, an appraisal sidetrack well was drilled down dip to delineate the Anchor discovery well. The appraisal well encountered 694 feet of net oil pay in a hydrocarbon column of at least 1,800 feet in Inboard Lower Tertiary reservoirs. A second successful appraisal well, Anchor #3, was drilled in 2016 to a total depth of 34,022 feet.  A third successful appraisal well, Anchor #4, was spud in late 2016 and resulted in approximately 800 feet of net oil pay.

 

The primary terms in certain leases covering our Anchor Unit expired in 2014 and are expected to be held by continuous operations or the filing of and approval of an SOP.

 

We also operate and own a 100% working interest in two leases that are immediately south of the current Anchor Unit.  The Anchor Unit reservoir extends onto these blocks and reservoir simulation suggests additional wells in these leases are required to maximize recovery from this reservoir.  We are in discussions with Chevron and the Bureau of Safety and Environmental Enforcement (“BSEE”) to bring these two leases into the Anchor Unit as we seek to optimize the development of this field.

 

Exploration

 

As of December 31, 2016, we owned interests in 170 blocks within the deepwater U.S. Gulf of Mexico, representing approximately 979,200 gross (504,372 net) acres.  While we are currently focused on progressing our existing U.S. Gulf of Mexico discoveries into production, we also plan to continue our exploration activities, including searching for liquids–rich, high–value opportunities in the Atlantic Basin.

 

Geologic Overview

 

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

 

6


 

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.

 

Miocene

 

The subsalt Miocene trend is an established play in the deepwater U.S. Gulf of Mexico. Discoveries in this trend include Thunder Horse, Atlantis, Tahiti, Mad Dog, and Stampede. This trend is characterized by high quality reservoirs and fluid properties, resulting in high production well rates.

 

Inboard Lower Tertiary  

 

The Lower Tertiary reservoir is an older formation than the Miocene, and, as such, is generally deeper, with greater geologic complexity. The industry has been successful in terms of locating and drilling large hydrocarbon–bearing structures in this interval. The reservoir quality of the Lower Tertiary has proven to be highly variable. Some regions, including those areas in which many of the historical Lower Tertiary discoveries have been made, exhibit lower permeability and generally lower natural gas content compared to the Miocene horizon. However, a sub–region in the Lower Tertiary that has exhibited reservoir characteristics more similar to that of existing Miocene discoveries is the Inboard Lower Tertiary trend, which includes our oil discoveries at North Platte, Shenandoah and Anchor.

 

The Inboard Lower Tertiary is a trend located to the north of existing Outboard Lower Tertiary fields such as St. Malo, Jack and Cascade, which are all on production from the Lower Tertiary. We were an early mover in the Inboard Lower Tertiary trend, targeting specific lease blocks as early as 2006. We believe our Inboard Lower Tertiary prospects are characterized by large, well-defined structures of a similar size to Outboard Lower Tertiary discoveries, but are differentiated by what we believe to be better reservoir quality and energy based upon data from wells drilled at our North Platte, Shenandoah and Anchor discoveries.

 

Exploration Prospect Maturation Process

 

The process of maturing an exploration prospect from initial identification to drill-ready status begins with analyzing regional data, including industry well results, to understand a given trend’s specific geology and defining those areas, or “prospects,” that offer the highest potential for substantial hydrocarbon deposits while minimizing geologic risks. After these prospects are identified, we further mature our prospects by acquiring and reprocessing high resolution seismic data available in the potential prospect’s direct vicinity. This includes advanced imaging information, such as wide–azimuth and full azimuth seismic data, to further our understanding of a particular prospect’s characteristics, including both trapping mechanics and fluid migration patterns.

 

Plans for Appraisal and Development

 

In general, the life cycle of our major project developments begins with a thorough evaluation and analysis of well logs (including offset analog wells), reservoir core samples, fluid samples and, in some cases, the results of production tests from the initial exploration and/or appraisal wells that encountered what we believe may be commercial hydrocarbons. This information, along with relevant seismic data, is used to generate locations and plans for appraisal and development wells. Depending upon the project, we may choose to drill one or more appraisal wells prior to project sanction and development, each of which will undergo thorough analysis and evaluation. The information we obtain from exploration and appraisal wells is then used to create a development plan, which will include economic assumptions on the costs of drilling and completing development wells, the front-end engineering and design of offshore production and processing facilities, including subsea, umbilical, riser and flowline systems and other related transportation infrastructure. The project will become formally sanctioned when the relevant working interest partners have approved the development plan. Typically, following formal project sanction, we will commence the construction of offshore production facilities, and proceed with development drilling and the installation of subsea architecture in order to advance the project towards initial production.

 

A discovery made by the initial exploration well on a prospect does not ensure that we will ultimately develop or produce hydrocarbons from such prospect or that a project development will be economically viable or successful. Following a discovery by an initial exploration well, substantial additional evaluation and analysis, such as the steps described above, will need to be performed prior to formal project sanction and development. In addition, substantial

 

7


 

amounts of capital are required to progress a project through the project development life-cycle. At any time during the project development life-cycle, we may determine that the project would be uneconomic and abandon the project, despite the fact that the initial exploration well, or subsequent appraisal wells, discovered hydrocarbons. See “Risk Factors—Risks Relating to Our Business—Our discoveries and appraisal and development projects remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to formal project sanction and production.”

 

Alliance with Total

 

In 2009, we announced a 10 year alliance with TOTAL E&P USA, INC. (“Total”) in which, through a series of transactions, we combined our respective U.S. Gulf of Mexico exploratory lease inventory (which excludes our Heidelberg project, Shenandoah project and our Anchor project (which was subsequently added to the excluded inventory), and all developed or producing properties held by Total in the U.S. Gulf of Mexico) through the exchange of a 40% interest in our leases for a 60% interest in Total’s leases.  The initial mandatory five well program and Total’s obligation to carry a substantial share of our drilling costs has concluded, but Total still remains obligated to pay its share of certain of the general and administrative costs relating to our operations in the deepwater U.S. Gulf of Mexico during the term of the alliance.

 

We act as operator on behalf of the alliance through the exploration and appraisal phases of development.  Upon completion of appraisal operations, operatorship will be determined by Total and ourselves, with the greatest importance being placed on majority (or largest) working interest ownership and the respective experience of each party in developments which have required the design, construction and ownership of a permanently anchored host facility to collect and transport oil or natural gas from such development. During the term of the alliance, we agreed to form a reciprocal area of mutual interest (“AMI”) with Total that covers substantially all of the deepwater U.S. Gulf of Mexico, subject to certain exclusions. Pursuant to the AMI, we may be obligated to offer Total its 40% share of any U.S. Gulf of Mexico leasehold interests we acquire and Total may be obligated to offer us our 60% share of any U.S. Gulf of Mexico leasehold interests that Total acquires.

 

West Africa

 

Our operations in West Africa consist of Block 20 and Block 21, both offshore Angola, and the Diaba Block offshore Gabon.  We forfeited our license on Block 9 offshore Angola in March 2016 pursuant to the terms of the Block 9 Risk Services Agreement with Sociedade Nacional de Combustíveis de Angola—Empresa Pública (“Sonangol”).

 

Angola Transaction

 

On August 22, 2015, we executed a Purchase and Sale Agreement (the “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 Agreement terminated by its terms in August 2016. Since then, we have been working with Sonangol to understand and agree on the financial and operational implications of the termination of the Agreement. As part of these discussions, we have requested that Sonangol extend certain deadlines for exploration and development milestones under the Production Sharing Contract (“PSC”) and Risk Services Agreement (“RSA”) governing Blocks 20 and 21, respectively (collectively, the “License Agreements”).  Under the Agreement, we are entitled to be put back in our original position as if no agreement had been concluded, which we believe requires Sonangol to extend all such deadlines by, at a minimum, the one year period the Agreement was pending plus the period of time from the termination of the Agreement until this matter is resolved.  

 

No extensions have been granted to date.  Over six months have passed since the termination of the Agreement and there can be no assurance that such extensions will be forthcoming on favorable terms or at all. The failure to receive such extensions would have a material adverse effect on the value of these License Agreements.  See “Risk Factors—Risks Relating to Our Business—We may be unable to consummate the sale of our Angolan assets on favorable terms, or at all” and “Under the terms of our various license agreements, we are required to drill wells,

 

8


 

declare any discoveries and conduct certain development activities in order to retain exploration and production rights.  Failure to do so may result in substantial license renewal costs or loss of our interests in these license areas.”  

 

We reserve the right to and will vigorously enforce the provisions of the Agreement if Sonangol does not grant the extensions we believe we are entitled to under the Agreement. The dispute resolution procedures of the Agreement require that any dispute be finally resolved under the Rules of Arbitration of the International Chamber of Commerce, with proceedings seated in London, England. In addition, prior to commencing arbitration proceeding, a party must provide the other party with a Notice of Dispute describing the nature of the dispute and the relief requested. Given Sonangol’s delays and failure to date to grant the extensions, on March 8, 2017, we submitted such a Notice of Dispute to Sonangol under the Agreement. If Sonangol does not timely resolve this matter to our satisfaction, we intend to move forward with arbitration and at that time we will seek all available remedies at law or in equity. Further, our Angolan assets are indirectly held by a German subsidiary, and we therefore believe we are entitled to certain protections provided under international law under the bilateral investment treaty between Germany and Angola, dated October 30, 2003, including its substantive and procedural protections to investments of German investors. 

 

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 at this time.  It is important to note that this impairment represents previously capitalized exploratory and appraisal well and other costs.  The impairment is not associated with, nor is it indicative of, what we believe to be the intrinsic or fair market value of our Angolan assets.  While we continue to market our Angola assets and believe they have substantial value to Cobalt, we believe the sale process has been negatively impacted by the uncertainty surrounding the extensions.  We further believe that Sonangol's preference is for us to present potential buyers to them prior to finalizing the terms of the extensions.

 

Although we plan to continue to fulfill our obligations as operator, we do not plan to make any material additional investments in Angola until the financial and operational implications of the termination of the Agreement are resolved to our satisfaction.  In addition, we are currently holding the $250 million initial payment that Sonangol made to us under the Agreement and do not plan to return any part of it until this matter, and the related matter concerning the joint interest receivable owed to us by Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) under the RSA, is resolved.  

 

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 (“BP”) and Sonangol P&P, with each partner holding a 30% working interest.  

 

Orca

 

In 2014, we drilled the successful Orca #1 exploratory well to a measured depth of 12,703 feet and encountered approximately 250 feet of net oil pay in the sag and syn–rift reservoirs, and we submitted a declaration of commercial well to Sonangol.  We completed drilling the Orca #2 appraisal well in 2015.  The results from this well, which included a drill stem test, were successful and confirmed the presence of a large oil accumulation in the sag section of the pre–salt and the discovery of oil in the deeper syn–rift reservoir of the pre–salt. The deadline to submit a declaration of commercial discovery was April 2016, but we were granted an extension to April 2017.  Notwithstanding the extensions we are seeking pursuant to the Agreement, we plan to timely file such declaration.  

 

 

9


 

Zalophus and Golfinho

 

In 2016, we completed the drilling of the Zalophus and Golfinho exploratory wells and submitted declarations of commercial well to Sonangol.  Without an extension pursuant to the Agreement, the deadlines for submitting a declaration of commercial discovery for Zalophus and Golfinho are not until April 2018 and June 2018, respectively. Both of these wells have been abandoned pending the results of studies in support of an appraisal decision.  The drilling of these two exploratory wells satisfied our minimum work obligations on Block 20, and our letter of credit collateralized by approximately $82.5 million in cash was released in 2016.

 

Lontra

 

In 2013, the initial Lontra #1 exploratory well was successfully drilled to a total depth of 13,763 feet and encountered approximately 250 feet of net pay in a very high quality reservoir section.  The well encountered both a high liquids content natural gas interval and an oil interval.  We submitted a declaration of commercial well to Sonangol in 2013, and the deadline to file a declaration of commercial discovery was in December 2015.  We requested an extension of this deadline from Sonangol and such extension was denied.  In addition, Presidential Decree No. 212/15 was passed in December 2015 which established a new Block 20/15 concession area covering our Lontra discovery.  It is unclear what effect the passage of the Presidential Decree has on our rights to develop Lontra under the PSC.  In light of the apparent conflict between Presidential Decree No. 212/15 and our rights under the PSC and the denial of our request for an extension of the declaration of commercial discovery deadline, we impaired the value of our Lontra discovery in 2015.  

 

License Information

 

We acquired our license to explore for, develop and produce oil from Block 20 by executing a 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.  We have asked Sonangol to extend this deadline, but there can be no assurance that such an extension will be forthcoming.  Without this extension, or the extensions we believe we are entitled to under the Agreement, the exploration period for Block 20 has ended.  We do not have contractual rights to sell natural gas on Block 20, but we have the right to use the natural gas during lease and production operations. Any stand–alone natural gas development cannot hinder or impede the development of liquid hydrocarbons on Block 20.

 

As required by the PSC, we are required to submit a declaration of commercial well to Sonangol within thirty days following a successful exploratory well.  Within the earlier of (i) two years after the date of the declaration of commercial well or (ii) six months after the second appraisal well is drilled, we must submit a formal, declaration of commercial discovery to Sonangol.  Within thirty days from the declaration of commercial discovery, we are required to submit a development plan to Sonangol and the Angola Ministry of Petroleum for review and approval.  Within 42 months after the formal declaration of commercial discovery, we are required to commence first production from such discovery.

 

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.  

 

Cameia

 

In 2012, the Cameia #1 exploratory well was successfully drilled in 5,518 feet of water to a total depth of 16,030 feet, at which point an extensive wireline evaluation program was conducted. The results of this wireline evaluation program confirmed the presence of a 1,180 foot gross continuous hydrocarbon column with over a 75% net to gross pay estimate.  Through 2016, we have drilled an additional three wells at Cameia.  No natural gas/oil or oil/water contact was evident on the wireline logs. We submitted a declaration of commercial well to Sonangol with respect to the Cameia #1 exploratory well in 2012. We also drilled the Cameia #2 appraisal well in 2012, which was located

 

10


 

approximately 2.2 miles south of the Cameia #1 exploratory well and was successful in demonstrating lateral continuity within the reservoir originally encountered by the Cameia #1 exploratory well. The results from the Cameia #2 appraisal well were also important as the well discovered a lower hydrocarbonbearing zone at least 440 feet deeper than that which was observed in the Cameia #1 exploratory well.    

 

In 2014, we submitted a formal declaration of commercial discovery to Sonangol, and we submitted the initial integrated field development plan for our Cameia project for approval by Sonangol and the Angola Ministry of Petroleum.  Since 2014, we have successfully drilled the Cameia #3, #4 and #5 development wells and completed additional drilling operations on the Cameia #1A well, each of which is planned to be used as part of a Cameia development. Sonangol has not acted on our integrated field development plan for Cameia.  Pursuant to discussions with Sonangol, further work on the Cameia development project was ceased while the sale to Sonangol was pending. We do not plan to reinitiate work on the Cameia development plan until, at the earliest, we understand and have agreed on the operational and financial implications of the termination of the Agreement, including the first oil deadline for Cameia. Without an extension pursuant to the Agreement, the first oil deadline for Cameia is August 2017.

 

Bicuar

 

In 2014, the Bicuar #1A exploratory well was successfully drilled to a total depth of 18,829 feet and encountered approximately 180 feet of net pay from multiple pre–salt intervals, and we submitted a declaration of commercial well to Sonangol. Without an extension pursuant to the Agreement, the deadline for submitting a declaration of commercial discovery for Bicuar has passed.  

 

Mavinga

 

In 2013, we announced that the Mavinga #1 exploratory well had reached total depth and encountered approximately 100 feet of net oil pay.  This discovery was confirmed by the successful production of oil from mini drill stem tests, direct pressure and permeability measurements and log and core analysis. We submitted a declaration of commercial well to Sonangol in 2013 regarding the Mavinga #1 exploration well. Without an extension pursuant to the Agreement, the deadline for submitting a declaration of commercial discovery for Mavinga has passed.

 

License Information

 

We acquired our license to explore for, develop and produce oil from Block 21 by executing an 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 pursuant to the Agreement, the exploration period for Block 21 ends in March 2017.  We do not have contractual rights to sell natural gas on Block 21, but we have the right to use the natural gas during lease and production operations. Any stand–alone natural gas development cannot hinder or impede the development of liquid hydrocarbons on Block 21.

 

As required by the RSA, we are required to submit a declaration of commercial well to Sonangol within thirty days following a successful exploratory well.  Within the earlier of two years after the date of the declaration of commercial well or six months after the second appraisal well is drilled, we must submit a formal, declaration of commercial discovery to Sonangol.  Within ninety days from the declaration of commercial discovery, we are required to submit a development plan to Sonangol and the Angola Ministry of Petroleum for review and approval.  Within 42 months after the formal declaration of commercial discovery, we are required to commence first production from such discovery.

 

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

 

11


 

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. We have contractual rights to any form of hydrocarbons, including natural gas, discovered on our Gabon license area.

 

Under the terms of the PSA and certain approved extensions, acreage not defined by an approved development area will expire in January 2018, subject to certain additional extensions.  

 

In 2013, the Diaman #1B exploratory well was drilled to a total depth of 18,323 feet and encountered approximately 160 to 180 feet of net hydrocarbons in the objective pre–salt formations.  Through 2016, we have not drilled any additional wells.  Total Gabon does not currently expect to resume exploration drilling on the Diaba block until at least 2018, and is currently evaluating the various extension options on such block, at least one of which it expects to seek.

 

Geologic Information

 

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.

 

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

 

12


 

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, 2016:

 

 

 

Oil

(MMBbls)

 

 

Natural Gas

(Bcf)

 

 

Natural Gas Liquids

(MMBbls)

 

 

MMBOE

 

Proved reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

1.9

 

 

 

0.8

 

 

 

0.1

 

 

 

2.1

 

Undeveloped

 

 

1.1

 

 

 

0.4

 

 

 

 

 

 

1.2

 

Total

 

 

3.0

 

 

 

1.2

 

 

 

0.1

 

 

 

3.3

 

 

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. All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.

 

We annually review all PUDs to ensure an appropriate plan for development exists. As of December 31, 2016, none of our PUDs have remained part of our PUD inventory for more than five years following the date they were initially classified as PUDs.  We plan to convert our PUDs as of December 31, 2016 to proved developed reserves within five years of the date they were included as part of our PUD inventory of drilling locations by drilling one gross well at a total estimated gross capital cost of $80.9 million.

 

The following table describes the changes in our PUDs during 2016:

 

 

 

MMBOE

 

PUDs as of December 31, 2015

 

 

6.2

 

Revisions of previous estimates

 

 

(2.5

)

Converted to proved developed reserves

 

 

(2.5

)

PUDS as of December 31, 2016

 

 

1.2

 

 

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.  

 

Our Reserve Estimation Policy is administered by the Reserves Process Chair (“RPC”).  The RPC is accountable for the completion of the annual and any in–year reserve estimates conducted by NSAI.  James H. Painter, our President, Exploration and Appraisal, acts in the role of RPC.  Mr. Painter has over 37 years of experience in the oil and natural gas industry.  Mr. Painter has a Bachelor of Science in Geology from Louisiana State University.

 

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

 

13


 

NSAI for purposes of their reserve estimation process. Our qualified technical team has over 100 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.

 

Developed and Undeveloped Acreage

 

The following table sets forth information related to our developed and undeveloped acreage as of December 31, 2016:

 

 

 

Developed

Lease Acres

 

 

Undeveloped

Lease Acres (1)

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

United States:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Heidelberg

 

 

17,280

 

 

 

1,620

 

 

 

 

 

 

 

North Platte

 

 

 

 

 

 

 

 

23,040

 

 

 

13,824

 

Shenandoah

 

 

 

 

 

 

 

 

14,400

 

 

 

2,880

 

Anchor

 

 

 

 

 

 

 

 

20,160

 

 

 

4,032

 

Other

 

 

 

 

 

 

 

 

904,320

 

 

 

482,016

 

Total United States

 

 

17,280

 

 

 

1,620

 

 

 

961,920

 

 

 

502,752

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Africa:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Block 20 (2)

 

 

 

 

 

 

 

 

1,210,569

 

 

 

484,228

 

Block 21 (2)

 

 

 

 

 

 

 

 

1,210,816

 

 

 

484,326

 

Gabon

 

 

 

 

 

 

 

 

2,242,634

 

 

 

476,560

 

Total West Africa

 

 

 

 

 

 

 

 

4,664,019

 

 

 

1,445,114

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

17,280

 

 

 

1,620

 

 

 

5,625,939

 

 

 

1,947,866

 

 

(1)

Projects not yet sanctioned for development are classified as undeveloped.  If development projects are sanctioned, we will evaluate which acreage associated with these projects could then be classified as developed acreage.

 

(2)

As Sonangol has not yet extended certain deadlines for exploration and development milestones under the License Agreements, we impaired these leases in 2016.  

 

14


 

The royalties on our lease blocks in the Gulf of Mexico range from 12.5% to 18.75% with an average of 16.86%.

 

Most of our U.S. Gulf of Mexico blocks have a 10 year primary term, expiring between 2017 and 2025. 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:

 

 

 

Year Ended December 31,

 

 

 

2017 (1) (2)

 

 

2018 (2) (3) (4)

 

 

2019

 

 

2020

 

 

2021 and Thereafter

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

United

   States (5)

 

 

28,800

 

 

 

14,132

 

 

 

420,480

 

 

 

204,618

 

 

 

63,360

 

 

 

39,317

 

 

 

11,520

 

 

 

5,184

 

 

 

380,160

 

 

 

218,765

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West

   Africa (6)

 

 

2,421,385

 

 

 

968,554

 

 

 

2,242,634

 

 

 

476,560

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

2,450,185

 

 

 

982,686

 

 

 

2,663,114

 

 

 

681,178

 

 

 

63,360

 

 

 

39,317

 

 

 

11,520

 

 

 

5,184

 

 

 

380,160

 

 

 

218,765

 

 

(1)

Includes portions of the estimated acreage covering our Shenandoah project in the U.S. Gulf of Mexico.  Exploratory and appraisal wells have both discovered hydrocarbons, but a development project has not yet be sanctioned.  The acreage in the Shenandoah project is part of the Shenandoah Unit, which was federally approved in 2014.  We expect that operations will continue to be conducted on this project in 2017 and that an application for an SOP in order to perpetuate this acreage will be filed at a future date.  

 

(2)

Includes portions of the estimated acreage covering our North Platte project in the U.S. Gulf of Mexico.  Exploratory and appraisal wells have both discovered hydrocarbons, but a development project has not yet been sanctioned.  The acreage in the North Platte project is part of the North Platte Unit, which was federally approved in 2016.  We expect that operations will continue to be conducted on the project in 2017 or that an application for an SOP in order to perpetuate this acreage will be filed at a future date.

 

(3)

Include portions of the estimated acreage covering our Anchor project in the U.S. Gulf of Mexico.  Exploratory and appraisal wells have both discovered hydrocarbons, but a development project has not yet been sanctioned. The acreage in the Anchor project is part of the Anchor Unit, which was federally approved in 2014.  We expect that operations will continue to be conducted on this project in 2017 or that an application for an SOP in order to perpetuate this acreage will be filed at a future date.  

 

(4)

Includes 11,520 gross (9,792 net) of acreage in two leases that are contiguous to the south of the Anchor Unit.  This acreage may have the potential to be included within the Anchor Unit.

 

(5)

Does not include acreage associated with our North Platte, Shenandoah and Anchor projects, whose primary terms have expired but are being held by continuous operations.  We expect that operations will continue to be conducted on these projects during 2017 or that an application for an SOP in order to perpetuate this acreage will be filed at a future date.

 

(6)

As Sonangol has not yet extended certain deadlines for exploration and development milestones under the License Agreements, we impaired these leases in 2016.  

 

15


 

Drilling Activity

 

The following table summarizes our approximate gross and net interest in wells completed by us during 2016, 2015 and 2014, 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 number of wells drilled, quantities of reserves found or economic value.

 

 

 

2016

 

 

2015

 

 

2014

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

United States:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

3

 

 

 

1.0

 

 

 

3

 

 

 

1.0

 

 

 

1

 

 

 

0.2

 

Dry

 

 

1

 

 

 

0.7

 

 

 

 

 

 

 

 

 

2

 

 

 

0.3

 

Total

 

 

4

 

 

 

1.7

 

 

 

3

 

 

 

1.0

 

 

 

3

 

 

 

0.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

1

 

 

 

0.1

 

 

 

2

 

 

 

0.2

 

 

 

1

 

 

 

0.1

 

Dry

 

 

 

 

 

 

 

 

1

 

 

 

0.1

 

 

 

 

 

 

 

Total

 

 

1

 

 

 

0.1

 

 

 

3

 

 

 

0.3

 

 

 

1

 

 

 

0.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

5

 

 

 

1.8

 

 

 

6

 

 

 

1.3

 

 

 

4

 

 

 

0.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Africa:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

2

 

 

 

0.8

 

 

 

1

 

 

 

0.4

 

 

 

3

 

 

 

1.2

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2

 

 

 

0.8

 

Total

 

 

2

 

 

 

0.8

 

 

 

1

 

 

 

0.4

 

 

 

5

 

 

 

2.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

 

4

 

 

 

1.2

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

4

 

 

 

1.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

2

 

 

 

0.8

 

 

 

5

 

 

 

1.6

 

 

 

5

 

 

 

2.0

 

 

As of December 31, 2016, we were participating in the drilling of four gross (1.1 net) wells in the U.S. Gulf of Mexico (including wells that are temporarily suspended).  This does not include wells that have been drilled to their targeted depth and then temporarily or permanently plugged and abandoned.

 

Productive Wells

 

As of December 31, 2016, we had four gross (0.4 net) productive oil wells in our Heidelberg field.  

 

 

16


 

Drilling Rig Commitments

 

United States

 

In 2013, we executed a drilling contract with Rowan (UK) Reliance Companies plc (“Rowan”) that provided for a firm three–year commitment which began in February 2015, at a day rate of $0.6 million (inclusive of mobilization fees).  We amended this contract in 2016.  This amendment provides for the following:

 

 

the contract terminates on March 31, 2017 instead of February 1, 2018;

 

 

we agreed to pay Rowan $95.9 million, of which $76.3 million was paid in 2016, in order to compensate Rowan for amending the term of the contract;

 

 

the early termination fee provided for in the contract was removed;

 

 

should our usage of the drillship be ongoing after March 31, 2017, the operating rate will be reduced from $0.6 million per day to $0.3 million per day and we will have the option to use the drillship or a comparable one at the reduced rate from March 31, 2017 through February 1, 2018; and

 

 

we will provide Rowan a five–year commitment to use Rowan as our exclusive provider of drilling services at market rate, provided Rowan is able to provide the necessary equipment and services that are legally and operationally qualified to perform the drilling services on the schedule we require.

 

West Africa

 

We released the Petroserv SSV Catarina in 2016 upon completion of operations on the Golfinho exploratory well.

 

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 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.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and there can be no assurances that we will be able to compete satisfactorily when attempting to make future acquisitions.

 

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.  We do not have contractual rights to sell natural gas on our Angola blocks, but we have the right to use the natural gas during lease and production operations. We do, however, have contractual rights to any natural gas from our U.S. Gulf of Mexico leases and, subject to negotiation of terms, our Gabon license area.  Our prospect interests are subject to applicable customary royalty and other interests, liens under operating agreements and secured credit facilities, 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.  With respect to our Angolan assets, we believe we are entitled to the extension of certain deadlines pursuant to the Agreement.  There can be no assurance that such extensions will be forthcoming, on favorable terms

 

17


 

or at all. The failure to receive such extensions would have a material adverse effect on the value of and title to these License Agreements.  See “Item 1 – Business – West Africa – Angola Transaction.”

 

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, (“HWCG”), Clean Gulf Associates (“CGA”), the Marine Preservation Association (“MPA”), and National Response Corporation (“NRC”).

 

HWCG serves as a contracting party for various oil spill and well containment equipment and services on behalf of the HWCG members. Our relationship with HWCG provides us access to the Helix Fast Response System which is currently capable of facilitating control and containment of spills in water depths up to 10,000 feet and can handle deep, higher pressure wells and could be used in the event a blowout preventer is ineffective.

 

As a member of CGA, we have access to a large inventory of fast response oil spill recovery vessels for offshore response scenarios with remote sensing technology for locating oil slicks. In addition, the CGA fleet includes significant shoreline protection equipment and near-shore oil skimming vessels.

 

As a member of MPA, we have access to the resources of the Marine Spill Response Corporation (“MSRC”). MSRC provides a wide variety of surface spill equipment, including a deepwater response fleet, aerial dispersant fleet, and approximately 75% of the existing dispersant material in the U.S. Gulf of Mexico region.

 

NRC is an umbrella response corporation that provides us access to a wide variety of surface spill response equipment as well as a wide group of surface response contractors that can address a surface response as well as play a support role in addressing a subsea well containment event.

 

In addition to the memberships above, 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.

 

For offshore West Africa, when we had active drilling operations, we had contracts in place with Wild Well Control which provided for subsea well control planning, response management, and access to two capping stack systems, subsea debris removal equipment package, and subsea dispersant application equipment in air freight configuration for mobilization to Angola. We also had contracts in place for the provision of oil spill management, equipment and response services. Specifically, we had contracted with (i) Braemer–Howells, a U.K.–based company with staff in Angola, which provides us access to oil spill response management, equipment and services, (ii) the West and Central African Aerial Surveillance and Dispersant Service, a non–profit organization which provides aerial surveillance and chemical dispersant services offshore Angola utilizing aircraft based in Ghana, and (iii) Oil Spill Response Limited, a U.K.–based company which is wholly owned by exploration and production companies and provides us access to personnel and equipment for oil spill events. We have also developed an Oil Spill Response Plan to address any potential spill, and we have access to equipment which is pre-staged in Angola, including containment boom, skimming systems, chemical dispersant systems, and temporary oil storage systems.    

 

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.

 

 

18


 

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 $450 million including coverage for third party bodily injury or death, property damage and cleanup of pollution on a sudden and accidental basis, (iii) an insurance policy with limits of $150 million for pollution damages as defined under the Oil Pollution Act of 1990 (“OPA”), and (iv) property insurance for our interest in the Anadarko operated Heidelberg field with limits of full replacement cost value.  

 

In July 2016, the Bureau of Ocean Energy Management (“BOEM”) issued Notice to Lessees No. 2016-N01 (“NTL”) detailing procedures to determine a lessee’s ability to carry out its lease obligations – primarily the decommissioning of Outer Continental Shelf (OCS) facilities – and whether to require lessees to furnish additional financial assurance.  While we do not currently foresee this obligation to have a material adverse effect on our liquidity and ability to operate in the U.S. Gulf of Mexico, changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

 

We believe that our coverage limits are sufficient and are consistent with what is held by our peers; 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. The continuation of the recent severe declines in oil and natural gas prices has had a negative impact on the foreign currency exchange market for the Angola Kwanza, which in turn has made it more difficult for our insurance provider in Angola to obtain foreign currency in an amount sufficient to procure adequate reinsurance.  The inability of our insurance provider to obtain adequate reinsurance may jeopardize our insurance coverage or otherwise impair their ability to perform their obligations under our insurance policies and agreements.

 

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 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 elect to self–insure or maintain only catastrophic coverage for certain risks in the future.

 

 

19


 

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:

 

 

require the acquisition of various permits before drilling commences;

 

 

require the installation of pollution control equipment in connection with operations;

 

 

place restrictions or regulations upon the use or disposal of the material utilized in our operations;

 

 

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas exploration, drilling, production and transportation activities;

 

 

limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas;

 

 

govern gathering, transportation and marketing of oil and natural gas pipeline and facilities construction;

 

 

require remedial measures to mitigate or address pollution from our operations; and

 

 

require the expenditure of significant amounts in connection with worker health and safety.

 

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 for 2017 through 2019.  

 

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

 

Impact of the U.S. Gulf of Mexico Oil Spill in 2010

 

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, 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 U.S. Department of the Interior (“DOI”) and two of its agencies, the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), which together formerly comprised the Bureau of Ocean Energy 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.  

 

These 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 including the submission of independent third party written certifications as to the capabilities of certain safety devices, such as blowout preventers and their components, (ii) the Workplace Safety Rule, which requires operators to develop and implement a comprehensive Safety and

 

20


 

Environmental Management System (“SEMS”) for oil and natural gas operations and codifies and makes mandatory the American Petroleum Institute’s Recommended Practice 75, (iii) Notice to Lessees (“NTL”) No 2010–N06, which sets forth requirements for exploration plans, development and production plans and development operations coordination documents to include a blowout scenario, the assumptions and calculations that are used to determine the volume of the worst case discharge scenario, and proposed measures to prevent and mitigate a blowout and (iv) NTL No. 2010–N10, which requires that each operator submit adequate information demonstrating that it has access to and can deploy containment resources that would be adequate to promptly respond to a blowout or other loss of well control, adds additional requirements to oil spill response plans and requires that operators submit written certifications stating that the operator will conduct all authorized activities in compliance with all applicable regulations.

 

In 2013, we conducted our own internal SEMS assessment and conducted a third party SEMS audit to ensure we were in compliance with all applicable regulations related to our SEMS; however, 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 Outer Continental Shelf (“OCS”) leases. In September 2016, BSEE published the final rule which includes among other things, 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.

 

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.  To date, compliance with these new regulations has been managed with minimal operational impact; however, the regulations required to be implemented in the future could result in some delays of our drilling or production operations.

 

Finally, in July 2016, BOEM issued Notice to Lessees No. 2016-N01 (“NTL”) 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.   We do not foresee this obligation to have a material adverse effect on our liquidity and ability to operate in the U.S. Gulf of Mexico.

 

Resource Conservation and Recovery Act

 

The U.S. Resource Conservation and Recovery Act (the “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, 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.

 

21


 

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.

 

Clean Water Act

 

The Federal Water Pollution Control Act of 1972, or Clean Water Act, as amended (“CWA”), imposes restrictions and strict controls on the discharge of pollutants, produced waters and other oil and natural gas wastes into waters of the United States. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future.

 

Under the CWA, permits must be obtained from the EPA to discharge pollutants into regulated waters. In addition, certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other hazardous substances and imposes liability on parties responsible for those discharges for the costs of cleaning up related damage and for natural resource damages resulting from the release. Comparable state statutes impose liabilities and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

 

Oil Pollution Act

 

The primary federal law for oil spill liability is the Oil Pollution Act of 1990, (the “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 in an amount that 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. Although defenses exist to the liability imposed by OPA, they are limited.

 

Clean Air Act

 

Our operations are subject to the federal Clean Air Act, or 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 requirements of the CAA or other air pollution laws and regulations, including the suspension or termination of permits and monetary fines. The EPA also proposed new air regulations for oil and natural gas exploration, production, transmission and storage. In May 2016, the EPA issued final updated new source performance standards

 

22


 

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. 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.

 

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.

 

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

 

23


 

U.S. Congress has at times considered the passage of laws to limit GHG emissions, while some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs. 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 do not believe, however, that our compliance with applicable monitoring, recordkeeping and reporting requirements under the GHG reporting program as recently amended will have a material adverse effect on our results of operations or financial position. 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 June 2013, the Obama Administration released its Climate Action Plan (“CAP”) that, among other things, called upon the EPA to promulgate greenhouse gas regulations for new and existing power plants. To that end, the EPA finalized the Clean Power Plan in August 2015, which sets forth binding guidelines for GHG emissions from existing power plants, as well as rules relating to GHG emissions from new, modified and reconstructed power plants. The EPA is also required pursuant to a settlement agreement to issue GHG emissions standards for oil refineries, but no such standards have been proposed to date. In addition, CAP called upon the EPA and other governmental agencies to identify ways in which to reduce methane emissions from various sectors, including the oil and natural gas industry. 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.  Additionally, the EPA and the National Highway Traffic Safety Administration administer GHG emissions standards for heavy, medium and light duty vehicles, which have become increasingly stringent over time.  The most recent standards were issued in 2012 for light duty vehicle model years 2017 through 2025 and, in August 2016, the two agencies finalized a new set of such standards for medium and heavy duty vehicles model years 2018 through 2027. Depending on the regulatory reach of CAA legislation implementing regulations or new EPA and/or state, regional or local rules restricting the emission of GHGs, we could incur significant costs to control our emissions and comply with regulatory requirements.

 

On the international level, in April 2016, 195 nations, including the United States, Angola and Gabon, signed and officially entered into an international climate change accord (the “Paris Agreement”), which calls for 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.  The Paris Agreement is in effect a successor to the Kyoto Protocol, pursuant to which 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. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.  Each of these

 

24


 

pending, proposed and future laws, regulations and initiatives could have a material adverse effect on us directly as well as indirectly, as they could decrease the demand for oil and natural gas.

 

OSHA and Other Laws and Regulations

 

To the extent not preempted by other applicable laws, 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 with existing requirements will not have a material adverse impact on our financial condition and results of operations; however, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition or 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:

 

 

the location of wells;

 

 

the method of drilling and casing wells;

 

 

25


 

 

the plugging and abandoning of wells and decommissioning of related equipment; and

 

 

produced water and disposal of waste water, drilling fluids and other liquids and solids utilized or produced in the drilling and extraction process.

 

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.

 

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

 

26


 

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 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.

 

 

27


 

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.

 

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.

 

 

28


 

Employees

 

As of December 31, 2016, we had 111 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, 2016, we had 37 contractors, consultants and secondees working in our offices and field locations.

 

In 2016, in response to the decline in oil prices and in light of the then proposed sale transaction with Sonangol, we undertook a reduction in force that eliminated 117 full time employees and 98 contractors.

 

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 Securities Exchange Act of 1934, as amended (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.

EXECUTIVE OFFICERS 

 

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

 

Name

 

Age

 

 

Position

Timothy J. Cutt

 

 

56

 

 

Chief Executive Officer

David D. Powell

 

 

58

 

 

Chief Financial Officer

Rodney M. Skaufel

 

 

54

 

 

President, Operations

James H. Painter

 

 

59

 

 

President, Exploration and Appraisal

Jeffrey A. Starzec

 

 

40

 

 

Executive Vice President, General Counsel and Secretary

Richard A. Smith

 

 

57

 

 

Senior Vice President, Strategy and Business Development

 

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

 

29


 

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.

 

James H. Painter has served as President, Exploration and Appraisal since January 2017.  Mr. Painter previously served as Executive Vice President from April 2013 until December 2016, and as Executive Vice President, Gulf of Mexico from our inception in November 2005 until April 2013. Mr. Painter has more than 37 years of experience in the oil and natural gas industry. Prior to joining Cobalt, from February 2004 to September 2005, Mr. Painter was the Senior Vice President of Exploration and Technology at Unocal Corporation. Prior to his position at Unocal Corporation (following the merger between Ocean Energy Inc. and Devon Energy Corporation), from April 2003 to October 2003, Mr. Painter served as the Vice President of Exploration at Devon Energy Corporation, an oil and natural gas exploration and production company. From January 1995 to April 2003, Mr. Painter served in various manager and executive positions at Ocean Energy Inc. (and its predecessor Flores and Rucks, Inc.) with his final position as Senior Vice President of Gulf of Mexico and International Exploration. Additional industry experience includes positions at Forest Oil Corporation, an independent oil and natural gas exploration and production company, Mobil Oil Corporation and Superior Oil Company, Inc. Mr. Painter holds a Bachelor of Science in Geology from Louisiana State University.

 

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.

 

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.

 

 

30


 

ITEM 1A.

RISK FACTORS

 

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 Business

 

Our substantial level of indebtedness, which may increase over time, could reduce our financial flexibility.  We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

 

As of March 1, 2017, we have $1.8 billion aggregate principal amount of convertible senior notes (the “Convertible Notes”) and $1.2 billion aggregate principal amount of first lien and second lien senior secured notes (the “Secured Notes” and, together with the Convertible Notes, the “Notes,”) outstanding.  We are restricted from incurring certain additional indebtedness pursuant to these debt instruments in the future.  In addition to our debt obligations, we have a substantial amount of contractual commitments pursuant to our license and lease agreements, among other things.  Our level of indebtedness could affect our operations in several ways, including the following:

 

 

a high level of indebtedness may impair our ability to obtain additional financing in the future for our development projects, exploration drilling program, working capital, capital expenditures, acquisitions, general corporate or other purposes;

 

 

a significant portion or all of our cash flows could be used to service our indebtedness;

 

 

a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions, such as the continued downturn in oil and natural gas prices; and

 

 

a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing.

 

A high level of indebtedness increases the risk that we may default on our debt obligations.  Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance and our ability to borrow or otherwise use money to service, repay or refinance our indebtedness. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.

 

Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, restrictive covenants in our existing debt agreements, the value of our assets and our performance at the time we need capital. In particular, weakness in the financial markets or other financing sources due to continued depressed prices for oil and natural gas may delay or prevent us from accessing additional funding sources to refinance and/or service our existing indebtedness. Further, there may be a material adverse effect on our liquidity and financial condition if we are unable to consummate key operational transactions, including the sale of our working interests in Blocks 20 and 21 offshore Angola and certain U.S. Gulf of Mexico assets.  If any of these adverse conditions occur or continue, we may not be able to generate sufficient cash flows to pay the principal and interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness.  If we are unable to satisfy our obligations under our debt agreements, our creditors could elect to declare some or all of our debt to be immediately due and payable, our

 

31


 

secured noteholders could elect to commence foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation.

 

In order to increase our liquidity to levels sufficient to meet our debt service obligations, we are currently considering a number of actions, including minimizing capital expenditures, considering asset sales, aggressively managing working capital and issuing new debt or equity. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.

 

We may be unable to continue as a going concern.

 

We have substantial debt obligations and our ongoing capital and operating expenditures will vastly exceed the revenue we expect to receive from our oil and natural gas operations in the near future.  If we are unable to raise substantial additional funding or consummate significant asset sales on a timely basis and/or on acceptable terms, we may be required to significantly curtail our exploration, appraisal and development activities. 

 

The consolidated financial statements included in this Annual Report on Form 10–K have been prepared on a going concern basis of accounting, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The consolidated financial statements do not reflect any adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern is subject to, among other factors, our ability to monetize assets, our ability to obtain financing or refinance existing indebtedness, our ability to continue our cost cutting efforts, the production rates achieved from our discoveries, oil and natural gas prices, the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed and cost with which we can bring such discoveries to production, whether and to what extent we invest in additional oil leases and concessional licenses, and the actual cost of exploration, appraisal and development of our prospects.  There can be no assurance that we will be able to obtain additional funding on a timely basis and on satisfactory terms, or at all.  In addition, no assurance can be given that any such funding, if obtained, will be adequate to meet our capital needs and support our growth.  If additional funding cannot be obtained on a timely basis and on satisfactory terms, then our operations would be materially negatively impacted.

 

If we become unable to continue as a going concern, we may find it necessary to file a voluntary petition for reorganization under the Bankruptcy Code in order to provide us additional time to identify an appropriate solution to our financial situation and implement a plan of reorganization aimed at improving our capital structure. For additional information, please see “Item 8. Financial Statements and Supplementary Data” contained herein.  

 

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 activities or renew our exploration portfolio.

 

In 2016, we generated $16.8 million of oil, natural gas and natural gas liquids revenues.  Our capital outlays and operating expenditures will increase substantially over at least the next several years as we expand our operations and will vastly exceed the revenue we receive 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 expensive, and we expect that we will need to raise substantial additional capital, through future private or public equity offerings, asset sales, strategic alliances or debt or project financing. The recent significant and sustained decline in oil and natural gas prices may make it more difficult for us to obtain additional financing.  

 

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

 

 

our ability to consummate key divestments or acquisitions, including the sale of our interests in Blocks 20 and 21 offshore Angola;

 

 

32


 

 

the performance of the producing wells on our Heidelberg development;

 

 

the scope, rate of progress and cost of our exploration, appraisal and development activities;

 

 

lack of partner participation in exploration, appraisal or development operations;

 

 

the extent to which we invest in additional oil leases or concessional licenses;

 

 

oil and natural gas prices;

 

 

our ability to locate and acquire hydrocarbon reserves;

 

 

our ability to produce oil or natural gas from those reserves;

 

 

our ability to meet the timelines for development set forth in our leases;

 

 

the terms and timing of any drilling and other production-related arrangements that we may enter into; and

 

 

the timing of partner and governmental approvals and/or concessions.

 

Our business plan requires us to raise a substantial amount of capital. Additional financing may not be available on favorable terms, or at all, due to our substantial level of indebtedness, the restrictions in our indentures governing our Secured Notes, the continuing downturn in oil and natural gas prices 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 similar to, or more restrictive than, those that govern our Secured Notes, 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 the continued 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 could have a material adverse effect on our liquidity and results of operations.

 

We may be unable to consummate the sale of our Angolan assets on favorable terms, or at all.

 

In August 2016, the Agreement for the sale of our 40% working interest in each of Block 20 and Block 21 offshore Angola was automatically terminated pursuant to its terms.  The Agreement provided that, upon termination of the Agreement, the parties are to be restituted in order to put them in their original positions as if no agreement had been executed.  We are working with Sonangol to understand and agree on the financial and operational implications of the termination.  We have requested that Sonangol extend certain deadlines for exploration and development milestones under our License Agreements. See “–Under the terms of our various license agreements, we are required to drill wells, declare any discoveries and conduct certain development activities in order to retain exploration and production rights.  Failure to do so may result in substantial license renewal costs or loss of our interests in these license areas.”  There can be no assurance that such extensions will be forthcoming, on favorable terms or at all.  The failure to receive such extensions would have a material adverse effect on the value of these License Agreements.  

 

We reserve the right to and will vigorously enforce the provisions of the Agreement if Sonangol does not grant the extensions we believe we are entitled to under the Agreement. The dispute resolution procedures of the Agreement require that any dispute be finally resolved under the Rules of Arbitration of the International Chamber of Commerce, with proceedings seated in London, England. In addition, prior to commencing arbitration proceeding, a party must provide the other party with a Notice of Dispute describing the nature of the dispute and

 

33


 

the relief requested. Given Sonangol’s delays and failure to date to grant the extensions, on March 8, 2017, we submitted such a Notice of Dispute to Sonangol under the Agreement. If Sonangol does not timely resolve this matter to our satisfaction, we intend to move forward with arbitration and at that time we will seek all available remedies at law or in equity.

 

In addition, discussions concerning the payment of certain joint interest receivables owed to us by an affiliate of Sonangol and the return of the first installments paid to us by Sonangol upon the execution of the Agreement are ongoing.  Furthermore, the Angolan government passed Presidential Decree No. 212/15 which established a new Block 20/15 concession area covering our Lontra discovery.  This decree ostensibly conflicts with our rights to develop oil from the Lontra discovery under the PSC. Accordingly, it is unclear what effect the passage of this decree has on our rights to develop Lontra under the PSC.  There can be no assurance that we will be able to come to an agreement with Sonangol concerning these items on satisfactory terms or at all.  The failure to do so could have a material adverse effect on the value of our licenses and our ability to sell them.  The inability to sell our Angolan assets to a third party on acceptable terms, or at all, or the failure to receive payment in full of the joint interest receivables owed to us, would each have a material adverse effect on our business, results of operations and financial condition, including our ability to service and/or repay our substantial existing indebtedness.  

 

Under the terms of our various license agreements, we are required to drill wells, declare any discoveries and conduct certain development activities in order to retain exploration and production rights.  Failure to do so may result in substantial license renewal costs or loss of our interests in these license areas.

 

In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various license agreements and leases, our interests in the undeveloped parts of our license (as is the case in Angola and Gabon) or the whole block (as is the case in the deepwater U.S. Gulf of Mexico) may lapse and we may be subject to significant penalties or be required to make additional payments in order to maintain such licenses.

 

Furthermore, as required by our License Agreements, within thirty days following a successful exploration well, we are required to submit a declaration of commercial well to Sonangol. Within the earlier of (i) two years after the date of the declaration of commercial well or (ii) six months after the second appraisal well is drilled, we must submit a formal, declaration of commercial discovery to Sonangol.  Within thirty days (in the case of Block 20) or 90 days (in the case of Block 21) from the declaration of commercial discovery, we are required to submit a development plan to Sonangol and the Angola Ministry of Petroleum for review and approval.  Within 42 months after the formal declaration of commercial discovery, we are required to commence first production from such discovery.  Our failure or inability to meet these deadlines could jeopardize our production rights or result in forfeiture of our production rights with respect to these projects, which would have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

 

Certain drilling and declaration requirements will be very difficult to achieve with respect to our Cameia, Orca and Lontra discoveries and may require the need to renegotiate our License Agreements with Sonangol. Without the extensions we believe we are entitled to under the Agreement, the deadline to file a declaration of commercial discovery with respect to our Lontra discovery was in December 2015. Given the sale of our Angolan assets was pending at such time, we did not meet that deadline, although we requested an extension of this deadline from Sonangol and such extension was denied. Furthermore, Presidential Decree No. 212/15 was passed in December 2015 which established a new Block 20/15 concession area covering our Lontra discovery. It is unclear what effect the passage of this Presidential Decree has on our rights under the PSC with respect to our Lontra discovery.  Presidential Decree Laws may need to be passed in Angola, along with the renegotiation of our PSC, in order to preserve our development rights with respect to Lontra. In light of (i) the apparent conflict between Presidential Decree No. 212/15 and our rights under the PSC and (ii) the denial of our request for an extension of the declaration of commercial discovery deadline with respect to Lontra, we impaired the value of our Lontra discovery in 2015.

 

In addition, most of our deepwater U.S. Gulf of Mexico blocks have a 10 year primary term, expiring between 2017 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

 

34


 

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 or licenses 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 nonoperated interest, will be able to successfully perpetuate leases through continuous operations or obtaining an SOP.  Should the prospects we have identified under the licenses or 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 licenses over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such licenses 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 and license areas, we cannot assure you that any renewals or extensions will be granted or whether any new agreements or 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 severe downturn in oil and natural gas prices over the last few years has 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:

 

 

changes in supply and demand for oil and natural gas;

 

 

the actions of the Organization of the Petroleum Exporting Countries;

 

 

the price and quantity of imports of foreign oil and natural gas;

 

 

speculation as to the future price of oil and the speculative trading of oil futures contracts;

 

 

global economic conditions;

 

 

political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activities, particularly in the Middle East, Africa, Russia and South America;

 

 

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

 

 

the level of global oil and natural gas exploration and production activity;

 

 

the level of global oil and natural gas inventories and oil and natural gas refining capacities;

 

 

weather conditions and other natural disasters;

 

 

technological advances affecting energy consumption;

 

 

domestic and foreign governmental regulations;

 

 

proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

35


 

 

the price and availability of competitors’ supplies of oil and natural gas; and

 

 

the price and availability of alternative fuels.

 

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

 

 

limiting our financial condition, liquidity, ability to finance our capital expenditures and results of operations;

 

 

reducing the amount of oil and natural gas that we can produce economically;

 

 

causing us to delay, postpone or terminate our exploration, appraisal and development activities;

 

 

reducing any future revenues, operating income and cash flows;

 

 

reducing the carrying value of our oil and natural gas properties; or

 

 

limiting our access to sources of capital, such as equity and long–term debt.

 

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.

 

Our indentures governing the Secured Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could have a material adverse effect on our ability to meet our future goals or raise additional capital.

 

Our indentures governing the Secured Notes include certain covenants that, among other things, restrict:

 

 

our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments;

 

 

our incurrence of additional secured indebtedness (including project finance indebtedness);

 

 

the granting of liens, other than liens created pursuant to the indenture governing the Senior Secured Notes and certain permitted liens;

 

 

mergers, consolidations and sales of all or a substantial part of our business or licenses; and

 

 

the sale of assets.

 

All of these restrictive covenants may limit our ability to expand or pursue our business strategies as well as raise additional capital to fund our business operations or service our debt obligations. Our ability to comply with these and other provisions of our indentures governing the Secured Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control. The breach of any of these covenants could result in a default under the indentures governing the Secured Notes or the indenture governing the Convertible Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under such indentures, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders, successors or assignees under the Secured Notes could proceed against the collateral securing the indebtedness. If the indebtedness under our indentures governing the Secured Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. In addition, the limitations imposed by the indenture governing the Secured Notes on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing.

 

 

36


 

Provisions of our indentures governing the Notes could discourage an acquisition of us by a third party.

 

Certain provisions of the indentures governing the Notes could make it more difficult or more expensive for a third party to acquire us, or may even prevent a third party from acquiring us. For example, upon the occurrence of a “change of control” (as defined in the indentures governing the Secured Notes) and a “fundamental change” (as defined in the indentures governing the Convertible Notes), holders of the Notes will have the right, at their option, to require us to repurchase all of their Notes or any portion of the principal amount of such notes in integral multiples of $1,000 at, in the case of the Secured Notes, a premium to the aggregate principal amount of such Notes, and in the case of the Convertible Notes, to the aggregate principal amount of such Notes (in each case plus accrued and unpaid interest).  In addition, the acquisition of us by a third party could require us, under certain circumstances, to increase the conversion rate for our Convertible Notes for a holder who elects to convert its notes in connection with such acquisition. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.

 

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 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:

 

 

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

 

 

persistent low oil and natural gas prices;

 

 

inability to obtain sufficient and timely financing;

 

 

inability to attract and/or retain sufficient quantity of personnel with the skills required to bring these complex projects to production on schedule and on budget;

 

 

significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure could adversely affect project development;

 

 

inability to advance certain technologies;

 

 

inability to obtain partner or government approval for projects;

 

 

37


 

 

civil disturbances, anti-development activities, legal challenges or other interruptions which could prevent access; and

 

 

drilling hazards or accidents or natural disasters.

 

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

 

The productivity of the Heidelberg field is uncertain.

 

Oil, natural gas and natural gas liquids production from the Heidelberg field commenced in January 2016.  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. 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.

 

 

38


 

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 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

 

39


 

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. The long–term success of our business will depend in part upon whether these projects are successful from a technical, operational and economic perspective, which we will have limited ability to control or influence as a non–operator.

 

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:

 

 

the timing and amount of capital expenditures;

 

 

the operator’s expertise and financial resources;

 

 

partner, government and regulatory approvals;

 

 

selection of technology; and

 

 

the rate of production of reserves, if any.

 

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.

 

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.

 

 

40


 

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, and any potential additional sites that may be developed, 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. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

 

We contract with third parties to conduct drilling and related services on our development projects and exploration prospects for us. Such third parties may not perform the services they provide us on schedule or within budget. The continued depression of oil and gas prices may have an adverse impact on certain third parties from which we contract drilling, development and related oilfield services, 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. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause a material adverse effect on our business, financial position and results of operations.

 

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

 

41


 

expect to commence production from those properties for a significant amount of time. Production from our oil and natural gas properties will depend upon our ability to execute the appraisal and development of our projects and progress our projects through the project appraisal and development life-cycle, including the approval of development plans, obtaining formal project sanction, achieving successful appraisal and development drilling results and constructing or leasing production facilities and related subsea infrastructure. Our ability to commence production from our other properties will also depend upon us being able to obtain substantial additional capital funding on a timely basis and attract and retain adequate personnel. We have only been generating revenue from operations for a very short period of time and expect to generate only limited revenue from production for several years. 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 substantial net losses as we continue our project appraisal and development activities, our exploration drilling program and our new venture activities. 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. In the event that our appraisal, development or exploration drilling schedules are not completed, or are delayed, modified or terminated, there would be a material adverse effect on our operating results and our operations will differ materially from the activities described in this Annual Report on Form 10-K. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.

 

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. The significant decline in oil and natural gas prices over the past eighteen months may make it more difficult for our partners to meet their obligations to us under applicable joint operating and other agreements. We may be unable to recover such outstanding amounts, which would materially negatively impact our liquidity and financial position.  Furthermore, in response to the recent 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 recent severe 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 or recruit 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

 

42


 

management and technical team, and their loss or departure could be detrimental to our future success. Our inability to retain or recruit 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 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:

 

 

blowouts, cratering and explosions;

 

 

mechanical and equipment problems;

 

 

uncontrolled flows or leaks of oil or well fluids, natural gas or other pollution;

 

 

fires and natural gas flaring operations;