10-Q 1 a14-19714_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

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

 

For the quarterly period ended September 30, 2014

 

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

 

For the transition period from               to         

 

Commission file number:  001-35167

 

 

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)

 

Bermuda

 

98-0686001

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

Clarendon House

 

 

2 Church Street

 

 

Hamilton, Bermuda

 

HM 11

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: +1 441 295 5950

 

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

 

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

 

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

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Class

 

Outstanding at October 28, 2014

Common Shares, $0.01 par value

 

386,872,550

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.

 

 

Page

PART I. FINANCIAL INFORMATION

 

 

 

Glossary and Select Abbreviations

3

 

 

Item 1. Financial Statements

 

Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013

6

Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013

7

Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2014 and 2013

8

Consolidated Statements of Shareholders’ Equity for the nine months ended September 30, 2014

9

Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013

10

Notes to Consolidated Financial Statements

11

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

24

Item 3. Quantitative and Qualitative Disclosures about Market Risk

34

Item 4. Controls and Procedures

35

 

 

PART II. OTHER INFORMATION

 

 

 

Item 1. Legal Proceedings

36

Item 1A. Risk Factors

36

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

37

Item 3. Defaults Upon Senior Securities

37

Item 4. Mine Safety Disclosures

37

Item 5. Other Information

37

Item 6. Exhibits

39

Signatures

40

Index to Exhibits

41

 

2



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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

 

The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.

 

“2D seismic data”

 

Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.

 

 

 

“3D seismic data”

 

Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.

 

 

 

“API”

 

A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.

 

 

 

“ASC”

 

Financial Accounting Standards Board Accounting Standards Codification.

 

 

 

“ASU”

 

Financial Accounting Standards Board Accounting Standards Update.

 

 

 

“Barrel” or “Bbl”

 

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

 

 

 

“BBbl”

 

Billion barrels of oil.

 

 

 

“BBoe”

 

Billion barrels of oil equivalent.

 

 

 

“Bcf”

 

Billion cubic feet.

 

 

 

“Boe”

 

Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.

 

 

 

“Boepd”

 

Barrels of oil equivalent per day.

 

 

 

“Bopd”

 

Barrels of oil per day.

 

 

 

“Bwpd”

 

Barrels of water per day.

 

 

 

“Debt cover ratio”

 

The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.

 

 

 

“Developed acreage”

 

The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

 

 

“Development”

 

The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.

 

 

 

“Dry hole”

 

A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.

 

 

 

“EBITDAX”

 

Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity-based compensation expense, (iv) unrealized (gain) loss on commodity derivatives, (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.

 

 

 

“E&P”

 

Exploration and production.

 

 

 

“FASB”

 

Financial Accounting Standards Board.

 

3



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“Farm-in”

 

An agreement whereby an oil company acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.

 

 

 

“Farm-out”

 

An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash or for the assignee taking on a portion of the drilling costs of one or more specific wells and/or other work as a condition of the assignment.

 

 

 

“Field life cover ratio”

 

The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of certain capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility.

 

 

 

“FPSO”

 

Floating production, storage and offloading vessel.

 

 

 

“Interest cover ratio”

 

The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.

 

 

 

“Loan life cover ratio”

 

The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the final maturity date of the Facility plus the net present value of capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility.

 

 

 

“Make-whole redemption price”

 

The “make-whole redemption price” is equal to the outstanding principal amount of such notes plus the greater of 1) 1% of the then outstanding principal amount of such notes and 2) the present value of the notes at 103.938% and required interest payments thereon through August 1, 2017 at such redemption date.

 

 

 

“MBbl”

 

Thousand barrels of oil.

 

 

 

“Mcf”

 

Thousand cubic feet of natural gas.

 

 

 

“Mcfpd”

 

Thousand cubic feet per day of natural gas.

 

 

 

“MMBbl”

 

Million barrels of oil.

 

 

 

“MMBoe”

 

Million barrels of oil equivalent.

 

 

 

“MMcf”

 

Million cubic feet of natural gas.

 

 

 

“Natural gas liquid” or “NGL”

 

Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.

 

 

 

“Petroleum contract”

 

A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.

 

 

 

“Petroleum system”

 

A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.

 

 

 

“Plan of development” or “PoD”

 

A written document outlining the steps to be undertaken to develop a field.

 

 

 

“Productive well”

 

An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

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“Prospect(s)”

 

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

 

 

 

“Proved reserves”

 

Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).

 

 

 

“Proved developed reserves”

 

Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

 

 

 

“Proved undeveloped reserves”

 

Proved undeveloped reserves are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.

 

 

 

“Reconnaissance contract”

 

A contract in which the owner of hydrocarbons gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but does not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.

 

 

 

“Shelf margin”

 

The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.

 

 

 

“Structural trap”

 

A structural trap is a topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.

 

 

 

“Structural-stratigraphic trap”

 

A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.

 

 

 

“Stratigraphy”

 

The study of the composition, relative ages and distribution of layers of sedimentary rock.

 

 

 

“Stratigraphic trap”

 

A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.

 

 

 

“Submarine fan”

 

A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.

 

 

 

“Three-way fault trap”

 

A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.

 

 

 

“Trap”

 

A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.

 

 

 

“Undeveloped acreage”

 

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

 

5



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KOSMOS ENERGY LTD.

 

CONSOLIDATED BALANCE SHEETS

 

(In thousands, except share data)

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

 

 

(Unaudited)

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

600,626

 

$

598,108

 

Restricted cash

 

34,621

 

21,475

 

Receivables:

 

 

 

 

 

Joint interest billings

 

54,027

 

19,930

 

Oil sales

 

41,764

 

281

 

Other

 

20,344

 

1,115

 

Inventories

 

57,571

 

47,424

 

Prepaid expenses and other

 

20,086

 

27,010

 

Current deferred tax assets

 

10,474

 

19,618

 

Derivatives

 

6,848

 

 

Total current assets

 

846,361

 

734,961

 

 

 

 

 

 

 

Property and equipment:

 

 

 

 

 

Oil and gas properties, net

 

1,641,393

 

1,508,062

 

Other property, net

 

12,208

 

14,900

 

Property and equipment, net

 

1,653,601

 

1,522,962

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

Restricted cash

 

16,125

 

31,500

 

Long-term receivables – joint interest billings

 

10,124

 

 

Deferred financing costs, net of accumulated amortization of $30,778 and $24,976 at September 30, 2014 and December 31, 2013, respectively

 

51,337

 

40,111

 

Long-term deferred tax assets

 

21,767

 

16,292

 

Derivatives

 

3,892

 

 

Total assets

 

$

2,603,207

 

$

2,345,826

 

 

 

 

 

 

 

Liabilities and shareholders’ equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

89,838

 

$

94,172

 

Accrued liabilities

 

197,132

 

115,212

 

Derivatives

 

1,994

 

9,940

 

Total current liabilities

 

288,964

 

219,324

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Long-term debt

 

794,106

 

900,000

 

Derivatives

 

429

 

3,811

 

Asset retirement obligations

 

42,861

 

39,596

 

Deferred tax liability

 

271,376

 

170,226

 

Other long-term liabilities

 

14,539

 

20,534

 

Total long-term liabilities

 

1,123,311

 

1,134,167

 

 

 

 

 

 

 

Shareholders’ equity:

 

 

 

 

 

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2014 and December 31, 2013

 

 

 

Common shares, $0.01 par value; 2,000,000,000 authorized shares; 392,388,533 and 391,974,287 issued at September 30, 2014 and December 31, 2013, respectively

 

3,924

 

3,920

 

Additional paid-in capital

 

1,840,615

 

1,781,535

 

Accumulated deficit

 

(623,621

)

(774,220

)

Accumulated other comprehensive income

 

1,057

 

2,158

 

Treasury stock, at cost, 5,543,118 and 4,400,135 shares at September 30, 2014 and December 31, 2013, respectively

 

(31,043

)

(21,058

)

Total shareholders’ equity

 

1,190,932

 

992,335

 

Total liabilities and shareholders’ equity

 

$

2,603,207

 

$

2,345,826

 

 

See accompanying notes.

 

6



Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(In thousands, except per share data)

 

(Unaudited)

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

Oil and gas revenue

 

$

137,485

 

$

215,169

 

$

678,635

 

$

636,648

 

Gain on sale of assets

 

 

 

23,769

 

 

Interest income

 

69

 

77

 

323

 

191

 

Other income

 

882

 

133

 

2,190

 

708

 

 

 

 

 

 

 

 

 

 

 

Total revenues and other income

 

138,436

 

215,379

 

704,917

 

637,547

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

Oil and gas production

 

15,097

 

32,576

 

54,366

 

79,651

 

Exploration expenses

 

21,334

 

75,607

 

57,652

 

194,384

 

General and administrative

 

35,148

 

38,077

 

95,041

 

118,787

 

Depletion and depreciation

 

36,959

 

58,367

 

152,883

 

175,578

 

Amortization—deferred financing costs

 

2,593

 

2,786

 

7,938

 

8,269

 

Interest expense

 

9,838

 

8,781

 

20,984

 

27,789

 

Derivatives, net

 

(40,407

)

7,585

 

(20,869

)

386

 

Restructuring charges

 

(46

)

 

11,758

 

 

Loss on extinguishment of debt

 

 

 

2,898

 

 

Other expenses, net

 

329

 

1,864

 

1,632

 

3,345

 

 

 

 

 

 

 

 

 

 

 

Total costs and expenses

 

80,845

 

225,643

 

384,283

 

608,189

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

57,591

 

(10,264

)

320,634

 

29,358

 

Income tax expense

 

38,468

 

34,224

 

170,035

 

124,568

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

19,123

 

$

(44,488

)

$

150,599

 

$

(95,210

)

 

 

 

 

 

 

 

 

 

 

Net income (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.05

 

$

(0.12

)

$

0.39

 

$

(0.25

)

Diluted

 

$

0.05

 

$

(0.12

)

$

0.39

 

$

(0.25

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of shares used to compute net income (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

379,969

 

377,654

 

378,881

 

376,509

 

Diluted

 

382,190

 

377,654

 

382,287

 

376,509

 

 

See accompanying notes.

 

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Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 

(In thousands)

 

(Unaudited)

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

19,123

 

$

(44,488

)

$

150,599

 

$

(95,210

)

Other comprehensive income:

 

 

 

 

 

 

 

 

 

Reclassification adjustments for gains on cash flow hedges included in net income (loss)

 

(290

)

(405

)

(1,101

)

(1,122

)

Other comprehensive income

 

(290

)

(405

)

(1,101

)

(1,122

)

Comprehensive income (loss)

 

$

18,833

 

$

(44,893

)

$

149,498

 

$

(96,332

)

 

See accompanying notes.

 

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Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

 

(In thousands)

 

(Unaudited)

 

 

 

Common Shares

 

Additional Paid-in

 

Accumulated

 

Accumulated
Other
Comprehensive

 

Treasury

 

 

 

 

 

Shares

 

Amount

 

Capital

 

Deficit

 

Income

 

Stock

 

Total

 

Balance as of December 31, 2013

 

391,974

 

$

3,920

 

$

1,781,535

 

$

(774,220

)

$

2,158

 

$

(21,058

)

$

992,335

 

Equity-based compensation

 

 

 

60,166

 

 

 

 

60,166

 

Derivatives, net

 

 

 

 

 

(1,101

)

 

(1,101

)

Restricted stock awards and units

 

415

 

4

 

(4

)

 

 

 

 

Restricted stock forfeitures

 

 

 

2

 

 

 

(2

)

 

Purchase of treasury stock

 

 

 

(1,084

)

 

 

(9,983

)

(11,067

)

Net income

 

 

 

 

150,599

 

 

 

150,599

 

Balance as of September 30, 2014

 

392,389

 

$

3,924

 

$

1,840,615

 

$

(623,621

)

$

1,057

 

$

(31,043

)

$

1,190,932

 

 

See accompanying notes.

 

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Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(In thousands)

 

(Unaudited)

 

 

 

Nine Months Ended September 30,

 

 

 

2014

 

2013

 

Operating activities

 

 

 

 

 

Net income (loss)

 

$

150,599

 

$

(95,210

)

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

 

 

 

 

 

Depletion, depreciation and amortization

 

160,821

 

183,847

 

Deferred income taxes

 

103,372

 

62,757

 

Unsuccessful well costs

 

3,091

 

98,912

 

Change in fair value of derivatives

 

(13,508

)

4,752

 

Cash settlements on derivatives

 

(9,661

)

(18,658

)

Equity-based compensation

 

59,941

 

50,792

 

Gain on sale of assets

 

(23,769

)

 

Loss on extinguishment of debt

 

2,898

 

 

Other

 

(4,368

)

4,468

 

Changes in assets and liabilities:

 

 

 

 

 

Increase in receivables

 

(104,708

)

(56,725

)

Increase in inventories

 

(10,197

)

(2,419

)

Decrease (increase) in prepaid expenses and other

 

6,924

 

(1,126

)

Decrease in accounts payable

 

(4,334

)

(30,037

)

Increase in accrued liabilities

 

55,133

 

79,996

 

Net cash provided by operating activities

 

372,234

 

281,349

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Oil and gas assets

 

(290,218

)

(244,452

)

Other property

 

(1,403

)

(3,712

)

Proceeds on sale of assets

 

58,315

 

 

Restricted cash

 

2,229

 

7,214

 

Net cash used in investing activities

 

(231,077

)

(240,950

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Payments on long-term debt

 

(400,000

)

(100,000

)

Net proceeds from issuance of senior secured notes

 

294,000

 

 

Purchase of treasury stock

 

(11,067

)

(13,069

)

Deferred financing costs

 

(21,572

)

(2,227

)

Net cash used in financing activities

 

(138,639

)

(115,296

)

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

2,518

 

(74,897

)

Cash and cash equivalents at beginning of period

 

598,108

 

515,164

 

Cash and cash equivalents at end of period

 

$

600,626

 

$

440,267

 

 

 

 

 

 

 

Supplemental cash flow information

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest

 

$

20,192

 

$

27,046

 

Income taxes

 

$

101,068

 

$

49,716

 

 

See accompanying notes.

 

10



Table of Contents

 

KOSMOS ENERGY LTD.

 

Notes to Consolidated Financial Statements

(Unaudited)

 

1. Organization

 

Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.

 

We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS.

 

We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and product sales are currently related to production located offshore Ghana.

 

2. Accounting Policies

 

General

 

The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2014, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2014, the consolidated results of operations for the three and nine months ended September 30, 2014 and 2013, and consolidated cash flows for the nine months ended September 30, 2014 and 2013. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2013, included in our annual report on Form 10-K.

 

Reclassifications

 

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or shareholders’ equity.

 

Restricted Cash

 

In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2014 and December 31, 2013, we had $15.5 million and $18.6 million, respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of September 30, 2014 and December 31, 2013, we had $19.1 million and $2.9 million, respectively, of current restricted cash and $16.1 million and $31.5 million, respectively, of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.

 

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Table of Contents

 

Inventories

 

Inventories consisted of $55.0 million and $45.8 million of materials and supplies and $2.6 million and $1.6 million of hydrocarbons as of September 30, 2014 and December 31, 2013, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or market.

 

Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or market. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

 

Restructuring Charges

 

The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards, the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the nine months ended September 30, 2014, we recognized $11.8 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan (the “LTIP”).

 

Recent Accounting Standards

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, “Revenue Recognition,” and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

 

In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The adoption of this new guidance is not expected to have a material impact on the Company’s consolidated financial statements.

 

3. Property and Equipment

 

Property and equipment is stated at cost and consisted of the following:

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Oil and gas properties:

 

 

 

 

 

Proved properties

 

$

865,500

 

$

801,348

 

Unproved properties

 

716,933

 

524,257

 

Support equipment and facilities

 

732,567

 

710,289

 

Total oil and gas properties

 

2,315,000

 

2,035,894

 

Less: accumulated depletion

 

(673,607

)

(527,832

)

Oil and gas properties, net

 

1,641,393

 

1,508,062

 

 

 

 

 

 

 

Other property

 

32,745

 

31,658

 

Less: accumulated depreciation

 

(20,537

)

(16,758

)

Other property, net

 

12,208

 

14,900

 

 

 

 

 

 

 

Property and equipment, net

 

$

1,653,601

 

$

1,522,962

 

 

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Table of Contents

 

We recorded depletion expense of $34.6 million and $56.1 million for the three months ended September 30, 2014 and 2013, respectively and $145.8 million and $169.2 million for the nine months ended September 30, 2014 and 2013, respectively.

 

In the first quarter of 2014, the Moroccan government issued a joint ministerial order approving a partial sale of our participating interests to BP Exploration (Morocco) Limited, a wholly owned subsidiary of BP plc (“BP”), covering our three blocks in the Agadir Basin, offshore Morocco. Upon receipt of this order, we closed the partial sale with BP. Under the terms of the agreements, BP acquired a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. The sales price of the farm-outs was $56.9 million. All proceeds were received as of June 30, 2014. After giving effect to these farm-outs, our participating interests are 30.0%, 29.925% and 30.0% in the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks, respectively, and we remain the operator. The proceeds on the sale of the interests exceeded our book basis in the assets, resulting in a $23.8 million gain on the transaction.

 

In the first quarter of 2014, the Moroccan government issued a joint ministerial order approving a partial sale of our participating interest to Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Offshore block, offshore Western Sahara. Upon receipt of this order, we closed the partial sale with Cairn. During the second quarter of 2014, Cairn paid $1.5 million for their share of costs incurred from the effective date of the farm-out agreement through the closing date, which was recorded as a reduction in our basis. After giving effect to the farm-out, our participating interest in the Cap Boujdour Offshore block is 55.0% and we remain the operator.

 

In August 2014, we entered into a farm-in agreement with Timis Corporation Limited, whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. As part of the agreement, we will carry the full costs of a planned 3D seismic program. Additionally, we will carry the full costs of two contingent exploration wells, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such wells. We also retain the option to increase our equity to 65% in exchange for carrying the full cost of a third contingent exploration or appraisal well, subject to a maximum gross cost of $120.0 million.

 

4. Suspended Well Costs

 

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2014. The table excludes $3.1 million in costs that were capitalized and subsequently expensed during the same period.

 

 

 

Nine Months
Ended

September 30,
2014

 

 

 

(In thousands)

 

Beginning balance

 

$

376,166

 

Additions to capitalized exploratory well costs pending the determination of proved reserves

 

53,367

 

Reclassification due to determination of proved reserves

 

 

Capitalized exploratory well costs charged to expense

 

 

Ending balance

 

$

429,533

 

 

The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:

 

 

 

September 30, 2014

 

December 31, 2013

 

 

 

(In thousands, except well counts)

 

Exploratory well costs capitalized for a period of one year or less

 

$

52,502

 

$

11,426

 

Exploratory well costs capitalized for a period of one to two years

 

137,367

 

229,140

 

Exploratory well costs capitalized for a period of three to five years

 

239,664

 

135,600

 

Ending balance

 

$

429,533

 

$

376,166

 

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

 

8

 

8

 

 

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Table of Contents

 

As of September 30, 2014, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak-1, Teak-2 and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Tweneboa, Enyenra, Ntomme and Wawa discoveries in the Deepwater Tano (“DT”) Block, which are all in Ghana.

 

Effective January 14, 2014, Ghana’s Ministry of Energy and Ghana National Petroleum Corporation (“GNPC”) entered into a Memorandum of Understanding with Kosmos Energy, on behalf of the WCTP Petroleum Agreement (“PA”) Block partners, wherein all parties have settled all matters pertaining to the Notices of Dispute for the Mahogany East PoD, and the Ministry of Energy has approved the Appraisal Programs for the Mahogany, Teak, and Akasa discoveries.

 

Mahogany— Three appraisal wells have been drilled. Additionally, we deepened a development well in the Jubilee Field to further appraise the Mahogany discovery. Following additional appraisal and evaluation, a decision regarding commerciality of the Mahogany discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

 

Teak-1 Discovery—Two appraisal wells have been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-1 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

 

Teak-2 Discovery—We have performed a gauge installation on the well and are reprocessing seismic data. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-2 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

 

Akasa Discovery—We performed a drill stem test and gauge installation on the discovery well and drilled one appraisal well. Following additional appraisal and evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

 

Tweneboa, Enyenra and Ntomme (“TEN”) Discoveries—In May 2013, the government of Ghana approved the PoD over the TEN discoveries. Development of TEN has commenced and is expected to include the drilling and completion of up to 24 development wells, half of the wells are designed as producers, with the remaining wells designed for water or gas injection. The TEN project is expected to deliver first oil in the second half of 2016. The costs associated with the TEN development will remain as unproved property pending the determination of whether the discoveries are associated with proved reserves.

 

Wawa Discovery—We are currently reprocessing seismic data and have acquired a high resolution seismic survey over the discovery area. Following additional evaluation and potential appraisal activities, a decision regarding commerciality of the Wawa discovery is expected to be made by the DT Block partners in 2016. Within six months of such declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the DT PA.

 

5. Accrued Liabilities

 

Accrued liabilities consisted of the following:

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Accrued liabilities:

 

 

 

 

 

Accrued exploration, development and production

 

$

150,149

 

$

73,976

 

Accrued general and administrative expenses

 

20,082

 

4,255

 

Accrued taxes other than income

 

18,472

 

15,188

 

Accrued interest

 

4,505

 

 

Income taxes

 

2,282

 

20,379

 

Accrued other

 

1,642

 

1,414

 

 

 

$

197,132

 

$

115,212

 

 

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Table of Contents

 

6. Debt

 

Debt consists of the following:

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Outstanding debt principal balances:

 

 

 

 

 

Facility

 

$

500,000

 

$

900,000

 

Senior Notes

 

300,000

 

 

Total

 

800,000

 

900,000

 

Unamortized issuance discounts

 

(5,894

)

 

Long-term debt

 

$

794,106

 

$

900,000

 

 

Facility

 

In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.

 

As part of the debt refinancing in March 2014, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and existing unamortized debt issuance costs attributable to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt. As of September 30, 2014, we have $46.4 million of net deferred financing costs related to the Facility, which will be amortized over the remaining term of the Facility, including certain costs related to the amendment.

 

As of September 30, 2014, borrowings under the Facility totaled $500.0 million and the undrawn availability under the Facility was $1.0 billion.

 

Interest is the aggregate of the applicable margin (3.25% to 4.50%, depending on the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. As part of the March 2014 amendment, the Facility’s estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense.

 

The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in March 2014 expires on March 31, 2018, however the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of September 30, 2014, we had no letters of credit issued under the Facility.

 

Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30 as part of a forecast that is prepared by and agreed to by us and the Technical and Modeling Bank and the Facility Agent. The formula to calculate the borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources.

 

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.

 

We were in compliance with the financial covenants contained in the Facility as of the September 30, 2014 forecast (the most recent assessment date).

 

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Table of Contents

 

Corporate Revolver

 

In November 2012, we secured a Corporate Revolver from a number of financial institutions. In April 2013, the availability under the Corporate Revolver was increased from $260.0 million to $300.0 million due to additional commitments received from existing and new financial institutions. As of September 30, 2014, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 million. The Corporate Revolver contains customary cross default provisions.

 

Revolving Letter of Credit Facility

 

In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. As of September 30, 2014, we had $35.3 million of restricted cash collateralizing seven outstanding letters of credit under the LC Facility. The LC Facility contains customary cross default provisions.

 

7.875% Senior Secured Notes due 2021

 

During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

 

The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries (the “Guarantees”).

 

Redemption and Repurchase.  At any time prior to August 1, 2017 and subject to certain conditions, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes issued under the indenture dated August 1, 2014 related to the Senior Notes (the “Indenture”) at a redemption price of 107.875%, plus accrued and unpaid interest, with the cash proceeds of certain eligible equity offerings. Additionally, at any time prior to August 1, 2017, the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a make-whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:

 

Year

 

Percentage

 

On or after August 1, 2017, but before August 1, 2018

 

103.938

%

On or after August 1, 2018, but before August 1, 2019

 

101.969

%

On or after August 1, 2019 and thereafter

 

100.000

%

 

We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

 

Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

 

If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

 

Covenants.  The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things:  incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock,  make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.

 

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Table of Contents

 

Collateral.  The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.

 

At September 30, 2014, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

 

 

 

Payments Due by Year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014(2)

 

2015

 

2016

 

2017

 

2018

 

Thereafter

 

 

 

(In thousands)

 

Principal debt repayments(1)

 

$

 

$

 

$

 

$

 

$

 

$

800,000

 

 


(1)                                Includes the scheduled principal maturities for the Senior Notes and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of September 30, 2014. Any increases or decreases in the level of borrowings or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

 

(2)                                Represents payments for the period October 1, 2014 through December 31, 2014.

 

7. Derivative Financial Instruments

 

We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions.

 

Oil Derivative Contracts

 

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 30, 2014.

 

 

 

 

 

 

 

Weighted Average Dated Brent Price per Bbl

 

Term

 

Type of Contract

 

MBbl

 

Net Deferred
Premium
Payable

 

Swap

 

Floor

 

Ceiling

 

Call

 

2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

October — December

 

Three-way collars

 

1,507

 

$

0.01

 

$

 

$

88.44

 

$

113.75

 

$

134.58

 

2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January — December

 

Three-way collars

 

4,230

 

$

0.46

 

$

 

$

87.43

 

$

110.00

 

$

133.82

 

January — December

 

Swaps with calls

 

2,000

 

 

99.00

 

 

 

115.00

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January — December

 

Purchased puts

 

2,000

 

$

3.41

 

$

 

$

85.00

 

$

 

$

 

 

Provisional Oil Sales

 

At September 30, 2014, we had sales volumes of 447.9 MBbls provisionally priced at an average of $92.95 per Bbl, after differentials, which are subject to final pricing during the next month.

 

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Table of Contents

 

Interest Rate Swap Derivative Contracts

 

The following table summarizes our open interest rate swaps as of September 30, 2014, whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate:

 

Term

 

Weighted Average
Notional Amount

 

Weighted Average
Fixed Rate

 

Floating Rate

 

 

 

(In thousands)

 

 

 

 

 

October 2014 — December 2014

 

$

110,555

 

1.93

%

6-month LIBOR

 

January 2015 — December 2015

 

45,319

 

2.03

%

6-month LIBOR

 

January 2016 — June 2016

 

12,500

 

2.27

%

6-month LIBOR

 

 

The following tables disclose the Company’s derivative instruments as of September 30, 2014 and December 31, 2013 and gain/(loss) from derivatives during the three and nine months ended September 30, 2014 and 2013, respectively:

 

 

 

 

 

Estimated Fair Value
Asset (Liability)

 

 

 

 

 

September 30,

 

December 31,

 

Type of Contract

 

Balance Sheet Location

 

2014

 

2013

 

 

 

 

 

(In thousands)

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

Derivative assets:

 

 

 

 

 

 

 

Commodity(1)

 

Derivatives assets—current

 

$

6,848

 

$

 

Commodity(2)

 

Derivatives assets—long-term

 

3,892

 

 

 

 

 

 

 

 

 

 

Derivative liabilities:

 

 

 

 

 

 

 

Commodity(3)

 

Derivatives liabilities—current

 

$

(523

)

$

(7,873

)

Interest rate

 

Derivatives liabilities—current

 

(1,471

)

(2,067

)

Commodity(4)

 

Derivatives liabilities—long-term

 

(282

)

(3,144

)

Interest rate

 

Derivatives liabilities—long-term

 

(147

)

(667

)

Total derivatives not designated as hedging instruments

 

 

 

$

8,317

 

$

(13,751

)

 


(1)                                 Includes net deferred premiums payable of $0.4 million and zero related to commodity derivative contracts as of September 30, 2014 and December 31, 2013, respectively.

 

(2)                                 Includes net deferred premiums payable of $3.6 million and zero related to commodity derivative contracts as of September 30, 2014 and December 31, 2013, respectively.

 

(3)                                Includes $0.1 million and zero as of September 30, 2014 and December 31 2013, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $0.9 million and $0.1 million related to commodity derivative contracts as of September 30, 2014 and December 31, 2013, respectively.

 

(4)                                 Includes net deferred premiums payable of $3.8 million and $6.5 million related to commodity derivative contracts as of September 30, 2014 and December 31, 2013, respectively.

 

 

 

 

 

Amount of Gain/(Loss)

 

Amount of Gain/(Loss)

 

 

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Type of Contract

 

Location of Gain/(Loss)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

(In thousands)

 

Derivatives in cash flow hedging relationships:

 

 

 

 

 

 

 

 

 

 

 

Interest rate(1)

 

Interest expense

 

$

290

 

$

405

 

$

1,101

 

$

1,122

 

Total derivatives in cash flow hedging relationships

 

 

 

$

290

 

$

405

 

$

1,101

 

$

1,122

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity(2)

 

Oil and gas revenue

 

$

(4,886

)

$

(554

)

$

(8,253

)

$

(5,220

)

Commodity

 

Derivatives, net

 

40,407

 

(7,585

)

20,869

 

(386

)

Interest rate

 

Interest expense

 

(2

)

(318

)

(209

)

(268

)

Total derivatives not designated as hedging instruments

 

 

 

$

35,519

 

$

(8,457

)

$

12,407

 

$

(5,874

)

 


(1)                                 Amounts were reclassified from accumulated other comprehensive income or loss (“AOCI”) into earnings upon settlement.

 

(2)                                 Amounts represent the mark-to-market portion of our provisional oil sales contracts.

 

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Offsetting of Derivative Assets and Derivative Liabilities

 

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2014 and December 31, 2013, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets. Additionally, if an event of default occurred the offsetting amounts would be immaterial as of September 30, 2014 and December 31, 2013.

 

8. Fair Value Measurements

 

In accordance with ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:

 

·                  Level 1—quoted prices for identical assets or liabilities in active markets.

 

·                  Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

 

·                  Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

 

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013, for each fair value hierarchy level:

 

 

 

Fair Value Measurements Using:

 

 

 

Quoted Prices in
Active Markets for
Identical Assets

 

Significant Other
Observable Inputs

 

Significant
Unobservable Inputs

 

 

 

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

(In thousands)

 

September 30, 2014

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

10,740

 

$

 

$

10,740

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

(805

)

 

(805

)

Interest rate derivatives

 

 

(1,618

)

 

(1,618

)

Total

 

$

 

$

8,317

 

$

 

$

8,317

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

(11,017

)

$

 

$

(11,017

)

Interest rate derivatives

 

 

(2,734

)

 

(2,734

)

Total

 

$

 

$

(13,751

)

$

 

$

(13,751

)

 

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, if any, after any allowances for doubtful accounts approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

 

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Table of Contents

 

Commodity Derivatives

 

Our commodity derivatives represent crude oil three-way collars, purchased puts and swaps with calls for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to the our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 7—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

 

Provisional Oil Sales

 

The value attributable to the provisional oil sales derivative is based on (i) the sales volumes subject to provisional pricing and (ii) an independently sourced forward curve over the term of the provisional pricing period.

 

Interest Rate Derivatives

 

We have interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.

 

Debt

 

The following table presents the carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets:

 

 

 

September 30, 2014

 

December 31, 2013

 

 

 

Carrying Value

 

Fair Value

 

Carrying Value

 

Fair Value

 

 

 

(In thousands)

 

Long-term debt

 

$

794,106

 

$

804,500

 

$

900,000

 

$

900,000

 

 

The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement.

 

9. Equity-based Compensation

 

Restricted Stock Awards and Restricted Stock Units

 

We record compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $19.0 million and $13.8 million during the three months ended September 30, 2014 and 2013, respectively, and $55.0 million and $50.8 million during the nine months ended September 30, 2014 and 2013. During the nine months ended September 30, 2014, an additional $5.0 million of equity-based compensation was recorded as restructuring charges. The total tax benefit for the three months ended September 30, 2014 and 2013 was $6.7 million and $4.8 million, respectively, and for the nine months ended September 30, 2014 and 2013 was $19.2 million and $17.4 million. Additionally, we expensed a tax shortfall related to equity-based compensation of $6.5 million and $6.9 million for the nine months ended September 30, 2014 and 2013 respectively. No tax shortfall was recorded for the three months ended September 30, 2014 and 2013. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service criteria under the LTIP. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.

 

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Table of Contents

 

The following table reflects the outstanding restricted stock awards as of September 30, 2014:

 

 

 

 

 

Weighted-

 

Market / Service

 

Weighted-

 

 

 

Service Vesting
Restricted Stock

 

Average
Grant-Date

 

Vesting
Restricted Stock

 

Average
Grant-Date

 

 

 

Awards

 

Fair Value

 

Awards

 

Fair Value

 

 

 

(In thousands)

 

 

 

(In thousands)

 

 

 

Outstanding at December 31, 2013

 

6,384

 

$

16.48

 

3,438

 

$

12.95

 

Granted

 

 

 

 

 

Forfeited

 

(115

)

15.58

 

(74

)

10.87

 

Vested

 

(2,799

)

17.04

 

 

 

Outstanding at September 30, 2014

 

3,470

 

16.05

 

3,364

 

12.99

 

 

The following table reflects the outstanding restricted stock units as of September 30, 2014:

 

 

 

 

 

Weighted-

 

Market / Service

 

Weighted-

 

 

 

Service Vesting
Restricted Stock

 

Average
Grant-Date

 

Vesting
Restricted Stock

 

Average
Grant-Date

 

 

 

Units

 

Fair Value

 

Units

 

Fair Value

 

 

 

(In thousands)

 

 

 

(In thousands)

 

 

 

Outstanding at December 31, 2013

 

2,238

 

$

10.74

 

1,858

 

$

15.59

 

Granted

 

1,962

 

10.95

 

1,462

 

15.71

 

Forfeited

 

(398

)

10.90

 

(179

)

15.48

 

Vested

 

(517

)

10.72

 

 

 

Outstanding at September 30, 2014

 

3,285

 

10.85

 

3,141

 

15.65

 

 

As of September 30, 2014, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $101.0 million over a weighted average period of 1.79 years. At September 30, 2014, the Company had approximately 2.4 million shares that remain available for issuance under the LTIP.

 

For restricted stock awards with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted. The grant date fair value of these awards ranged from $6.70 to $13.57 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7%. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.1%.

 

For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value of these awards ranged from $15.44 to $15.81 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 39.0% to 54.0%. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.2%.

 

10. Income Taxes

 

Income tax expense was $38.5 million and $34.2 million for the three months ended September 30, 2014 and 2013, respectively, and $170.0 million and $124.6 million for the nine months ended September 30, 2014 and 2013, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes.

 

The components of income (loss) before income taxes were as follows:

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(In thousands)

 

Bermuda

 

$

(8,368

)

$

(5,880

)

$

(20,588

)

$

(19,320

)

United States

 

3,049

 

2,740

 

10,542

 

8,014

 

Foreign—other

 

62,910

 

(7,124

)

330,680

 

40,664

 

Income (loss) before income taxes

 

$

57,591

 

$

(10,264

)

$

320,634

 

$

29,358

 

 

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Table of Contents

 

Our effective tax rate for the three months ended September 30, 2014 and 2013 is 67% and (333)%, respectively. For the nine months ended September 30, 2014 and 2013, our effective tax rate is 53% and 424%, respectively. The effective tax rate for the United States is approximately 38% and 42% for the three months ended September 30, 2014 and 2013, respectively, and 102% and 125% for the nine months ended September 30, 2014 and 2013, respectively. The effective tax rate in the United States is impacted by the effect of tax shortfalls related to equity-based compensation. The effective tax rate for Ghana is approximately 33% and 36% for the three months ended September 30, 2014 and 2013, respectively, and approximately 35% and 36% for the nine months ended September 30, 2014 and 2013, respectively. Our other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate, or we have experienced losses in those countries and have a full valuation allowance reserved against the corresponding net deferred tax assets.

 

The Company has no material unrecognized income tax benefits.

 

A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2012 through 2013 and to Texas margin tax examinations for the tax years 2009 through 2013. In addition, the Company is open to income tax examinations for years 2004 through 2013 in its significant other foreign jurisdictions (Ghana, Cameroon, Mauritania, Suriname and Morocco).

 

As of September 30, 2014, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense, but have not accrued any material amounts to date.

 

11. Net Income (Loss) Per Share

 

The following table is a reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income per share:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(In thousands, except per share data)

 

Numerator:

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

19,123

 

$

(44,488

)

$

150,599

 

$

(95,210

)

Less: Basic income allocable to participating securities(1)

 

(174

)

 

(1,919

)

 

Basic net income (loss) allocable to common shareholders

 

18,949

 

(44,488

)

148,680

 

(95,210

)

Diluted adjustments to income allocable to participating securities(1)

 

1

 

 

17

 

 

Diluted net income (loss) allocable to common shareholders

 

$

18,950

 

$

(44,488

)

$

148,697

 

$

(95,210

)

Denominator:

 

 

 

 

 

 

 

 

 

Weighted average number of shares used to compute net income (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

379,969

 

377,654

 

378,881

 

376,509

 

Restricted stock awards and units(1)(2)

 

2,221

 

 

3,406

 

 

Diluted

 

382,190

 

377,654

 

382,287

 

376,509

 

Net income (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.05

 

$

(0.12

)

$

0.39

 

$

(0.25

)

Diluted

 

$

0.05

 

$

(0.12

)

$

0.39

 

$

(0.25

)

 


(1)                                 Our service vesting restricted stock awards represent participating securities because they participate in nonforfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses and, therefore, are excluded from the basic net income per common share calculation in periods we are in a net loss position.

 

(2)                                 We excluded outstanding restricted stock awards of 6.8 million and 13.9 million for the three months ended September 30, 2014 and 2013, respectively, and 4.7 million and 13.9 million for the nine months ended September 30, 2014 and 2013, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

 

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Table of Contents

 

12. Commitments and Contingencies

 

We are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

 

In September 2014, we took delivery of the new build 6th generation drillship “Atwood Achiever” from Atwood Oceanics, Inc.  The rig is expected to commence drilling operations in Northwest Africa in the fourth quarter of 2014. The rig agreement covers an initial period of three years at a day rate of approximately $0.6 million, with an option to extend the agreement for an additional three-year term. We have entered into a rig sharing agreement, whereby two rig slots (estimated to be 90 days during 2015 and 70 days during 2016) were assigned to a third-party.

 

The estimated future minimum commitments as of September 30, 2014, are:

 

 

 

Payments Due By Year(1)

 

 

 

Total

 

2014(2)

 

2015

 

2016

 

2017

 

2018

 

Thereafter

 

 

 

(In thousands)

 

Operating leases

 

$

16,908

 

$

813

 

$

3,260

 

$

3,158

 

$

3,223

 

$

3,323

 

$

3,131

 

Atwood Achiever drilling rig contract (3)

 

540,855

 

54,740

 

163,625

 

176,120

 

146,370

 

 

 

 


(1)                                 Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

 

(2)                                 Represents payments for the period from October 1, 2014 through December 31, 2014.

 

(3)                                 Commitments calculated using a day rate of $595,000, excluding applicable taxes. The rig commitments reflect the execution of a rig sharing agreement, whereby two rig slots (estimated to be 90 days during 2015 and 70 days during 2016) were assigned to a third-party.

 

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Table of Contents

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2013, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

 

Overview

 

We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname.

 

We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of Kosmos Energy Ltd.’s IPO on May 16, 2011, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. As a result, Kosmos Energy Holdings became wholly owned by Kosmos Energy Ltd.

 

Recent Developments

 

Corporate

 

During August 2014, the Company issued $300.0 million of 7.875% Senior Secured Notes due 2021 (“Senior Notes”) and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

 

Rig Agreement

 

In September 2014, we took delivery of the new build 6th generation drillship “Atwood Achiever” from Atwood Oceanics, Inc. The rig is expected to commence drilling operations in northwest Africa in the fourth quarter of 2014. The rig agreement covers an initial period of three years at a day rate of approximately $0.6 million, with an option to extend the agreement for an additional three-year term. We have entered into a rig sharing agreement, whereby two rig slots (estimated to be 90 days in total during 2015 and 70 days during 2016) were assigned to a third-party.

 

Ghana

 

Approval was granted by the Government of Ghana and the Ghanaian Environmental Protection Agency in June 2014 to permit the flaring of 500 MMcf of gas per month from the Jubilee field until the end of October 2014. This limited flaring is expected to assist in the maintenance of existing production levels until the Western Corridor Gas Infrastructure (Jubilee Gas Export) is operational. We are working with the Government of Ghana and the Ghanaian Environmental Protection Agency to extend the limited flaring until Jubilee Gas Export is operational.

 

Morocco (including Western Sahara)

 

In June 2014, we commenced a 3D seismic survey of approximately 5,100 square kilometers over the Cap Boujdour Offshore block which was completed in September 2014.

 

Portugal

 

In August 2014, we entered into a farm-in agreement with Repsol Exploración, S.A. (“Repsol”), to acquire a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks offshore Portugal. As part of the agreement, we will reimburse a portion of Repsol’s previously incurred exploration costs, as well as partially carry Repsol’s share of the costs of a planned 3D seismic  program. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the blocks will be 31%.

 

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Table of Contents

 

Senegal

 

In August 2014, we entered into a farm-in agreement with Timis Corporation Limited, whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. As part of the agreement, we will carry the full costs of a planned 3D seismic program. Additionally, we will carry the full costs of two contingent exploration wells, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such wells. We also retain the option to increase our equity to 65% in exchange for carrying the full cost of a third contingent exploration or appraisal well, subject to a maximum gross cost of $120.0 million.

 

In September 2014, we commenced a 3D seismic survey of approximately 7,000 square kilometers over the Cayar Offshore Profond and Saint Louis Offshore Profond Contract Areas which is expected to be completed in the first quarter of 2015.

 

Results of Operations

 

All of our results, as presented in the table below, represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the three and nine months ended September 30, 2014 and 2013, are included in the following table:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(In thousands, except barrel and per barrel data )

 

Sales volumes:

 

 

 

 

 

 

 

 

 

MBbl

 

1,443

 

1,912

 

6,297

 

5,847

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

137,485

 

$

215,169

 

$

678,635

 

$

636,648

 

Average sales price per Bbl

 

95.26

 

112.52

 

107.78

 

108.88

 

 

 

 

 

 

 

 

 

 

 

Costs:

 

 

 

 

 

 

 

 

 

Oil production, excluding workovers

 

$

14,883

 

$

13,026

 

$

52,786

 

$

39,145

 

Oil production, workovers

 

214

 

19,550

 

1,580

 

40,506

 

Total oil production costs

 

$

15,097

 

$

32,576

 

$

54,366

 

$

79,651

 

 

 

 

 

 

 

 

 

 

 

Depletion

 

$

34,589

 

$

56,094

 

$

145,775

 

$

169,163

 

 

 

 

 

 

 

 

 

 

 

Average cost per Bbl:

 

 

 

 

 

 

 

 

 

Oil production, excluding workovers

 

$

10.31

 

$

6.82

 

$

8.38

 

$

6.69

 

Oil production, workovers

 

0.15

 

10.22

 

0.25

 

6.93

 

Total oil production costs

 

10.46

 

17.04

 

8.63

 

13.62

 

 

 

 

 

 

 

 

 

 

 

Depletion

 

23.97

 

29.33

 

23.15

 

28.93

 

Oil production cost and depletion costs

 

$

34.43

 

$

46.37

 

$

31.78

 

$

42.55

 

 

The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of September 30, 2014:

 

 

 

 

 

 

 

 

 

 

 

Wells Suspended or

 

 

 

Actively Drilling or Completing

 

Waiting on Completion

 

 

 

Exploration

 

Development

 

Exploration

 

Development

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Ghana

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jubilee Unit

 

 

 

1

 

0.24

 

 

 

1

 

0.24

 

West Cape Three Points