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, 2013

 

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, 2013

Common Shares, $0.01 par value

 

387,559,187

 

 

 



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, 2013 and December 31, 2012

6

Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012

7

Consolidated Statements of Comprehensive Loss for the three and nine months ended September 30, 2013 and 2012

8

Consolidated Statements of Shareholders’ Equity for the nine months ended September 30, 2013

9

Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012

10

Notes to Consolidated Financial Statements

11

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

22

Item 3. Quantitative and Qualitative Disclosures about Market Risk

31

Item 4. Controls and Procedures

33

 

 

PART II. OTHER INFORMATION

 

 

 

Item 1. Legal Proceedings

34

Item 1A. Risk Factors

34

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

34

Item 3. Defaults Upon Senior Securities

34

Item 4. Mine Safety Disclosures

34

Item 5. Other Information

34

Item 6. Exhibits

35

Signatures

36

Index to Exhibits

37

 

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 (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) equity-based compensation expense, (4) (gain) loss on commodity derivatives, (5) (gain) loss on sale of oil and gas properties, (6) interest (income) expense, (7) income taxes, (8) loss on extinguishment of debt, (9) doubtful accounts expense, and (10) similar items.

 

3



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“E&P”

 

Exploration and production.

 

 

 

“FASB”

 

Financial Accounting Standards Board.

 

 

 

“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.

 

 

 

“FPSO”

 

Floating production, storage and offloading vessel.

 

 

 

“Ghana Obligors”

 

Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Finance International, Kosmos Energy Development, Kosmos Energy Ghana HC and an “Obligor” from time to time, as defined under the Facility Agreement, as amended and restated.

 

 

 

“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.

 

 

 

“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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Table of Contents

 

“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 minerals 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 minerals 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,

 

 

 

2013

 

2012

 

 

 

(Unaudited)

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

440,267

 

$

515,164

 

Restricted cash

 

19,377

 

21,341

 

Receivables:

 

 

 

 

 

Joint interest billings

 

71,591

 

21,539

 

Oil sales

 

113,067

 

108,995

 

Other

 

4,995

 

3,682

 

Inventories

 

33,118

 

33,281

 

Prepaid expenses and other

 

11,596

 

10,470

 

Current deferred tax assets

 

14,515

 

34,585

 

Derivatives

 

917

 

1,061

 

Total current assets

 

709,443

 

750,118

 

 

 

 

 

 

 

Property and equipment:

 

 

 

 

 

Oil and gas properties, net

 

1,486,224

 

1,510,312

 

Other property, net

 

15,490

 

15,450

 

Property and equipment, net

 

1,501,714

 

1,525,762

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

Restricted cash

 

24,634

 

29,884

 

Deferred financing costs, net of accumulated amortization of $22,191 and $13,922 at September 30, 2013 and December 31, 2012, respectively

 

42,897

 

50,214

 

Long-term deferred tax assets

 

14,808

 

10,145

 

Derivatives

 

1,583

 

 

Total assets

 

$

2,295,079

 

$

2,366,123

 

 

 

 

 

 

 

Liabilities and shareholders’ equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

98,818

 

$

128,855

 

Accrued liabilities

 

115,866

 

41,021

 

Derivatives

 

9,458

 

20,377

 

Total current liabilities

 

224,142

 

190,253

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Long-term debt

 

900,000

 

1,000,000

 

Derivatives

 

1,335

 

3,226

 

Asset retirement obligations

 

35,226

 

27,484

 

Deferred tax liability

 

145,193

 

104,137

 

Other long-term liabilities

 

18,886

 

12,117

 

Total long-term liabilities

 

1,100,640

 

1,146,964

 

 

 

 

 

 

 

Shareholders’ equity:

 

 

 

 

 

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2013 and December 31, 2012

 

 

 

Common shares, $0.01 par value; 2,000,000,000 authorized shares; 391,956,419 and 391,423,703 issued at September 30, 2013 and December 31, 2012, respectively

 

3,920

 

3,914

 

Additional paid-in capital

 

1,763,227

 

1,712,880

 

Accumulated deficit

 

(778,386

)

(683,176

)

Accumulated other comprehensive income

 

2,563

 

3,685

 

Treasury stock, at cost, 4,397,232 and 2,731,941 shares at September 30, 2013 and December 31, 2012, respectively

 

(21,027

)

(8,397

)

Total shareholders’ equity

 

970,297

 

1,028,906

 

Total liabilities and shareholders’ equity

 

$

2,295,079

 

$

2,366,123

 

 

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,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

Oil and gas revenue

 

$

215,169

 

$

222,375

 

$

636,648

 

$

450,360

 

Interest income

 

77

 

137

 

191

 

1,165

 

Other income

 

133

 

725

 

708

 

930

 

 

 

 

 

 

 

 

 

 

 

Total revenues and other income

 

215,379

 

223,237

 

637,547

 

452,455

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

Oil and gas production

 

32,576

 

44,873

 

79,651

 

71,791

 

Exploration expenses

 

78,038

 

38,127

 

194,384

 

96,134

 

General and administrative

 

35,646

 

39,898

 

118,787

 

112,558

 

Depletion and depreciation

 

58,367

 

63,794

 

175,578

 

128,442

 

Amortization—deferred financing costs

 

2,786

 

2,194

 

8,269

 

6,582

 

Interest expense

 

8,781

 

20,213

 

27,789

 

43,717

 

Derivatives, net

 

7,585

 

24,529

 

386

 

26,407

 

Other expenses, net

 

1,864

 

(64

)

3,345

 

728

 

 

 

 

 

 

 

 

 

 

 

Total costs and expenses

 

225,643

 

233,564

 

608,189

 

486,359

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

(10,264

)

(10,327

)

29,358

 

(33,904

)

Income tax expense

 

34,224

 

25,923

 

124,568

 

64,730

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(44,488

)

(36,250

)

$

(95,210

)

(98,634

)

 

 

 

 

 

 

 

 

 

 

Net loss per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.12

)

(0.10

)

$

(0.25

)

(0.27

)

Diluted

 

$

(0.12

)

(0.10

)

$

(0.25

)

(0.27

)

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Basic

 

377,654

 

373,448

 

376,509

 

371,140

 

Diluted

 

377,654

 

373,448

 

376,509

 

371,140

 

 

See accompanying notes.

 

7



Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

 

(In thousands)

 

(Unaudited)

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(44,488

)

$

(36,250

)

$

(95,210

)

$

(98,634

)

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

Reclassification adjustments for derivative (gains) losses included in net loss

 

(405

)

(133

)

(1,122

)

295

 

Other comprehensive income (loss)

 

(405

)

(133

)

(1,122

)

295

 

Comprehensive loss

 

$

(44,893

)

$

(36,383

)

$

(96,332

)

$

(98,339

)

 

See accompanying notes.

 

8



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, 2012

 

391,424

 

$

3,914

 

$

1,712,880

 

$

(683,176

)

$

3,685

 

$

(8,397

)

$

1,028,906

 

Equity-based compensation

 

 

 

50,792

 

 

 

 

50,792

 

Derivatives, net

 

 

 

 

 

(1,122

)

 

(1,122

)

Restricted stock awards and units

 

532

 

6

 

(6

)

 

 

 

 

Restricted stock forfeitures

 

 

 

6

 

 

 

(6

)

 

Purchase of treasury stock

 

 

 

(445

)

 

 

(12,624

)

(13,069

)

Net loss

 

 

 

 

(95,210

)

 

 

(95,210

)

Balance as of September 30, 2013

 

391,956

 

$

3,920

 

$

1,763,227

 

$

(778,386

)

$

2,563

 

$

(21,027

)

$

970,297

 

 

See accompanying notes.

 

9



Table of Contents

 

KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(In thousands)

 

(Unaudited)

 

 

 

Nine Months Ended September 30,

 

 

 

2013

 

2012

 

Operating activities

 

 

 

 

 

Net loss

 

$

(95,210

)

$

(98,634

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation and amortization

 

183,847

 

135,024

 

Deferred income taxes

 

62,757

 

51,867

 

Unsuccessful well costs

 

98,912

 

19,357

 

Change in fair value of derivatives

 

4,752

 

13,847

 

Cash settlements on derivatives

 

(18,658

)

(18,755

)

Equity-based compensation

 

50,792

 

58,215

 

Other

 

4,468

 

7,739

 

Changes in assets and liabilities:

 

 

 

 

 

(Increase) decrease in receivables

 

(56,725

)

89,102

 

Increase in inventories

 

(2,419

)

(7,812

)

(Increase) decrease in prepaid expenses and other

 

(1,126

)

4,112

 

Decrease in accounts payable

 

(30,037

)

(127,025

)

Increase in accrued liabilities

 

79,996

 

23,073

 

Net cash provided by operating activities

 

281,349

 

150,110

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Oil and gas assets

 

(244,452

)

(272,681

)

Other property

 

(3,712

)

(9,030

)

Restricted cash

 

7,214

 

(23,089

)

Net cash used in investing activities

 

(240,950

)

(304,800

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Payment on long-term debt

 

(100,000

)

(110,000

)

Purchase of treasury stock

 

(13,069

)

(8,378

)

Deferred financing costs

 

(2,227

)

(374

)

Net cash used in financing activities

 

(115,296

)

(118,752

)

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(74,897

)

(273,442

)

Cash and cash equivalents at beginning of period

 

515,164

 

673,092

 

Cash and cash equivalents at end of period

 

$

440,267

 

$

399,650

 

 

 

 

 

 

 

Supplemental cash flow information

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest

 

$

27,046

 

$

30,247

 

Income taxes

 

$

49,716

 

$

16,620

 

 

See accompanying notes.

 

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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 asset portfolio includes existing production and other major project developments offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara) 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, 2013, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2013, the consolidated results of operations for the three and nine months ended September 30, 2013 and 2012, and consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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 (“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, 2012, 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 loss, current assets, total assets, current liabilities, total liabilities or shareholders’ equity.

 

Restricted Cash

 

In accordance with our commercial debt 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. As of September 30, 2013 and December 31, 2012, we had $19.4 million and $21.3 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 letters of credit will be satisfied and the cash collateral will be released. As of September 30, 2013 and December 31, 2012, we had $24.6 million and $29.9 million, respectively, of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.

 

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Inventories

 

Inventories consisted of $32.3 million and $33.1 million of materials and supplies and $0.8 million and $0.2 million of hydrocarbons as of September 30, 2013 and December 31, 2012, 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 directly and indirectly 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.

 

Variable Interest Entity

 

Our wholly owned subsidiary, Kosmos Energy Finance International, is a variable interest entity (“VIE”). The Company is the primary beneficiary of this VIE, which is consolidated in these financial statements.

 

Kosmos Energy Finance International’s following assets and liabilities are shown separately on the face of the consolidated balance sheet as of September 30, 2013 and December 31, 2012: current restricted cash; long-term derivatives assets; long-term debt; and current and long-term derivatives liabilities. At September 30, 2013, Kosmos Energy Finance International had $36.9 million in cash and cash equivalents; $0.4 million in prepaid expenses and other; $0.9 million current derivative assets; $36.2 million deferred financing costs, net; $1.5 million in accrued liabilities and $7.6 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet. At December 31, 2012, Kosmos Energy Finance International had $118.8 million in cash and cash equivalents; $0.2 million in prepaid expenses and other; $42.2 million deferred financing costs, net; $0.5 million in accrued liabilities and $6.6 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet.

 

3. Property and Equipment

 

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

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(In thousands)

 

Oil and gas properties:

 

 

 

 

 

Proved properties

 

$

767,288

 

$

682,276

 

Unproved properties

 

489,874

 

454,391

 

Support equipment and facilities

 

712,415

 

687,835

 

Total oil and gas properties

 

1,969,577

 

1,824,502

 

Less: accumulated depletion

 

(483,353

)

(314,190

)

Oil and gas properties, net

 

1,486,224

 

1,510,312

 

 

 

 

 

 

 

Other property

 

30,978

 

27,316

 

Less: accumulated depreciation

 

(15,488

)

(11,866

)

Other property, net

 

15,490

 

15,450

 

 

 

 

 

 

 

Property and equipment, net

 

$

1,501,714

 

$

1,525,762

 

 

We recorded depletion expense of $56.1 million and $61.9 million for the three months ended September 30, 2013 and 2012, respectively and $169.2 million and $123.3 million for the nine months ended September 30, 2013 and 2012, respectively.

 

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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, 2013. The table excludes $69.8 million in costs that were capitalized and subsequently expensed during the same period.

 

 

 

Nine Months
Ended

September 30,
2013

 

 

 

(In thousands)

 

Beginning balance 

 

$

 372,492

 

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

 

30,415

 

Reclassification due to determination of proved reserves

 

 

Capitalized exploratory well costs charged to expense

 

(26,997

)

Ending balance

 

$

375,910

 

 

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, 2013

 

December 31, 2012

 

 

 

(In thousands, except well counts)

 

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

 

$

11,470

 

$

106,635

 

Exploratory well costs capitalized for a period one to two years

 

228,842

 

179,933

 

Exploratory well costs capitalized for a period three to four years

 

135,598

 

85,924

 

Ending balance

 

$

375,910

 

$

372,492

 

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

 

8

 

7

 

 

As of September 30, 2013, 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.

 

Mahogany—Mahogany, a combined area covering parts of the Mahogany East discovery and the Mahogany Deep discovery, was declared commercial in September 2010, and a PoD was submitted to Ghana’s Ministry of Energy as of May 2, 2011. In a letter dated May 16, 2011, the Ministry of Energy did not approve the PoD and requested that the WCTP Block partners take certain steps regarding notifications of discovery and commerciality; and requested other information. The WCTP Block partners believe the combined submission was proper and have held meetings with Ghana National Petroleum Corporation (“GNPC”) which resolved issues relating to the PoD work program. From May 2011, the Ministry of Energy, GNPC and the WCTP Block partners continued working to resolve other differences; however, the WCTP Petroleum Agreement (“PA”) contains specific timelines for PoD approval and discussions, which expired at the end of June 2011. On June 30, 2011, we, as Operator of the WCTP Block and on behalf of the WCTP Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the government of Ghana regarding approval of the Mahogany PoD. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. We and the WCTP Block partners are in discussions with the Ministry of Energy and GNPC to resolve differences on the PoD.

 

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 2014. 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 2014. 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 have performed a drill stem test and gauge installation on the discovery well and are currently drilling the Akasa-2A appraisal well (see Note 13—Subsequent Events). Following additional appraisal and evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in 2014. 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.

 

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Tweneboa, Enyenra and Ntomme (“TEN”) Discoveries—In May 2013, the government of Ghana approved the PoD over the TEN discoveries. Development of TEN will include the drilling and completion of up to 24 development wells, half of the wells are designed as producers and the remainder are for water and gas injection to support ultimate field recoveries. The TEN project is expected to deliver first oil in 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 plan to acquire a high resolution seismic survey over the discovery area in 2014. 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 2014. 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. Accounts Payable and Accrued Liabilities

 

At September 30, 2013 and December 31, 2012, accounts payable of $98.8 million and $128.9 million, respectively, were recorded for invoices received but not paid. Accrued liabilities consisted of the following:

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(In thousands)

 

Accrued liabilities:

 

 

 

 

 

Accrued exploration, development and production

 

$

65,561

 

$

20,616

 

Accrued general and administrative expenses

 

14,896

 

5,089

 

Accrued taxes other than income

 

15,667

 

11,124

 

Accrued derivative settlements

 

1,465

 

 

Income taxes

 

18,277

 

4,192

 

 

 

$

115,866

 

$

41,021

 

 

6. Debt

 

Facility

 

In March 2011, the Company secured a $2.0 billion commercial debt facility (the “Facility”) from a number of financial institutions and extinguished the then existing commercial debt facilities. The Facility was syndicated to certain participants of the existing facilities, as well as new participants. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of an amendment in November 2012, the total commitments for the Facility were reduced to $1.5 billion.

 

The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in April 2013, expires on December 15, 2014 and the letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on December 15, 2014, outstanding borrowings will also be constrained by an amortization schedule. The final maturity date is March 29, 2018.

 

In September 2013, as part of the normal borrowing base determination process, the availability under the facility was reduced by $89.6 million to $1.2 billion. As of September 30, 2013, borrowings under the Facility totaled $900.0 million, the undrawn availability under the Facility was $309.5 million, and there were no letters of credit drawn under the facility.

 

Corporate Revolver

 

In November 2012, we secured a revolving credit facility (the “Corporate Revolver”). 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, 2013, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 million.

 

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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. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. The fees associated with outstanding letters of credit issued will be 0.5% per annum. The LC Facility has an availability period which expires on June 1, 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of September 30, 2013, there were four outstanding letters of credit totaling $29.0 million under the LC Facility.

 

At September 30, 2013, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

 

 

 

Payments Due by Year

 

 

 

2013(1)

 

2014

 

2015

 

2016

 

2017

 

Thereafter

 

 

 

(In thousands)

 

Facility(2)

 

$

 

$

 

$

346,693

 

$

149,428

 

$

292,768

 

$

111,111

 

 


(1)                                 Represents payments for the period October 1, 2013 through December 31, 2013.

(2)                                 The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of
September 30, 2013. 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.

 

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, 2013.

 

 

 

 

 

 

 

Weighted Average Dated Brent Price per Bbl

 

Term(1)

 

Type of Contract

 

MBbl

 

Deferred
Premium 
Receivable/ 
(Payable)

 

Floor

 

Ceiling

 

Call

 

2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

October - December

 

Three-way collars

 

375

 

$

(4.82

)

$

95.00

 

$

105.00

 

$

125.00

 

October - December

 

Three-way collars

 

253

 

 

87.50

 

115.00

 

135.00

 

October - December

 

Three-way collars

 

250

 

 

90.00

 

115.39

 

135.00

 

October - December

 

Three-way collars

 

250

 

 

90.08

 

115.00

 

135.00

 

2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

January - December

 

Three-way collars

 

1,500

 

(1.22

)

85.00

 

115.00

 

140.00

 

January - December

 

Three-way collars

 

1,000

 

 

85.00

 

115.01

 

140.00

 

January - December

 

Three-way collars

 

1,000

 

 

88.09

 

110.00

 

125.00

 

January - December

 

Three-way collars

 

1,500

 

1.15

 

90.00

 

113.00

 

135.00

 

 


(1)                                 In October 2013, we entered into put contracts for 1.7 MMBbl from January 2015 through December 2015 with a floor price of $85.00 per Bbl. The put contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $3.78 per Bbl.

 

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Interest Rate Swaps Derivative Contracts

 

The following table summarizes our open interest rate swaps as of September 30, 2013, 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 2013 — December 2013

 

$

200,617

 

1.99

%

6-month LIBOR

 

January 2014 — December 2014

 

133,434

 

1.99

%

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, 2013 and December 31, 2012 and gain/(loss) from derivatives during the three and nine months ended September 30, 2013 and 2012, respectively:

 

 

 

 

 

Estimated Fair Value
Asset (Liability)

 

 

 

 

 

September 30,

 

December 31,

 

Type of Contract 

 

Balance Sheet Location

 

2013

 

2012

 

 

 

 

 

(In thousands)

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

Derivative assets:

 

 

 

 

 

 

 

Commodity(1)

 

Derivatives assets—current

 

$

917

 

$

1,061

 

Commodity(2)

 

Derivatives assets—long-term

 

1,583

 

 

 

 

 

 

 

 

 

 

Derivative liabilities:

 

 

 

 

 

 

 

Commodity(3)

 

Derivatives liabilities—current

 

(6,284

)

(17,005

)

Interest rate

 

Derivatives liabilities—current

 

(3,174

)

(3,372

)

Commodity(4)

 

Derivatives liabilities—long-term

 

(319

)

(659

)

Interest rate

 

Derivatives liabilities—long-term

 

(1,016

)

(2,567

)

Total derivatives not designated as hedging instruments

 

 

 

$

(8,293

)

$

(22,542

)

 


(1)                                 The commodity derivative asset represents $0.9 million of our oil derivative contracts as of September 30, 2013 and $1.1 million of our provisional oil sales contract as of December 31, 2012. Includes deferred premiums receivable of $1.1 million and zero related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

 

(2)                                 Includes deferred premiums receivable of $0.6 million related to commodity derivative contracts as of September 30, 2013.

 

(3)                                 Includes zero and $3.4 million, as of September 30, 2013 and December 31, 2012, respectively of cash settlements made on our commodity derivative contracts which were settled in the month subsequent to period end. Also, includes deferred premiums payable of $3.0 million and $7.6 million related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

 

(4)                                 Includes deferred premiums payable of $0.6 million and $2.4 million related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

 

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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)

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

(In thousands)

 

Derivatives in cash flow hedging relationships:

 

 

 

 

 

 

 

 

 

 

 

Interest rate(1)

 

Interest expense

 

$

405

 

$

133

 

$

1,122

 

$

(295

)

Total derivatives in cash flow hedging relationships

 

 

 

$

405

 

$

133

 

$

1,122

 

$

(295

)

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

 

Commodity(2)

 

Oil and gas revenue

 

$

(554

)

$

11,494

 

$

(5,220

)

$

15,221

 

Commodity

 

Derivatives, net

 

(7,585

)

(24,529

)

(386

)

(26,407

)

Interest rate

 

Interest expense

 

(318

)

(931

)

(268

)

(2,366

)

Total derivatives not designated as hedging instruments

 

 

 

$

(8,457

)

$

(13,966

)

$

(5,874

)

$

(13,552

)

 


(1)                                 Amounts were reclassified from AOCI into earnings upon settlement.

 

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

 

In accordance with the mark-to-market method of accounting, the Company recognizes changes in fair values of its derivative contracts as gains or losses in earnings during the period in which they occur. The fair value of the effective portion of the interest rate derivative contracts on May 31, 2010, is reflected in AOCI and is being transferred to interest expense over the remaining term of the contracts. The Company expects to reclassify $1.5 million of gains from AOCI to interest expense within the next 12 months. See Note 8—Fair Value Measurements for additional information regarding the Company’s derivative instruments.

 

Offsetting of Derivative Assets and Derivative Liabilities

 

Our derivative instruments 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, 2013 and December 31, 2012, 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, there were no material rights of offset available, if an event of default occurred, as of September 30, 2013 and December 31, 2012.

 

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.

 

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012, 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, 2013

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

2,500

 

$

 

$

2,500

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

(6,603

)

 

(6,603

)

Interest rate derivatives

 

 

(4,190

)

 

(4,190

)

Total

 

$

 

$

(8,293

)

$

 

$

(8,293

)

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

1,061

 

$

 

$

1,061

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

(17,664

)

 

(17,664

)

Interest rate derivatives

 

 

(5,939

)

 

(5,939

)

Total

 

$

 

$

(22,542

)

$

 

$

(22,542

)

 

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. The carrying values of our debt approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods. 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.

 

Commodity Derivatives

 

Our commodity derivatives represent crude oil three-way collars 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 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 puts and compound options. 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.

 

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 Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $13.8 million and $19.4 million during the three months ended September 30, 2013 and 2012, respectively, and $50.8 million and $58.2 million during the nine months ended September 30, 2013 and 2012, respectively. The tax benefit resulting from equity-based compensation expense

 

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for the three months ended September 30, 2013 and 2012 was $4.8 million and $6.7 million, respectively, and for the nine months ended September 30, 2013 and 2012 was $17.4 million and $20.2 million, respectively. Additionally, we expensed a tax shortfall (the difference between the estimated tax deduction on the grant date and the actual tax deduction on the vest date) of $6.9 million and $7.4 million during the nine months ended September 30, 2013 and 2012, respectively. No shortfall occurred during the three months ended September 30, 2013 and 2012.

 

The following table reflects the outstanding restricted stock awards as of September 30, 2013:

 

 

 

 

 

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, 2012

 

9,898

 

$

16.92

 

3,534

 

$

12.93

 

Granted

 

351

 

10.73

 

 

 

Forfeited

 

(462

)

16.51

 

(93

)

12.45

 

Vested

 

(3,358

)

17.26

 

 

 

Outstanding at September 30, 2013

 

6,429

 

16.44

 

3,441

 

12.94

 

 

The following table reflects the outstanding restricted stock units as of September 30, 2013:

 

 

 

 

 

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, 2012

 

1,023

 

$

10.59

 

825

 

$

15.81

 

Granted

 

1,512

 

10.80

 

1,074

 

15.44

 

Forfeited

 

(133

)

10.53

 

(73

)

15.74

 

Vested

 

(225

)

10.51

 

 

 

Outstanding at September 30, 2013

 

2,177

 

10.75

 

1,826

 

15.60

 

 

As of September 30, 2013, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $144.7 million over a weighted average period of 2.20 years. At September 30, 2013, the Company had approximately 5.5 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 used to estimate the grant-date fair value 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 used to estimate the grant-date fair value 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 53.0% 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 0.7%.

 

10. Income Taxes

 

Income tax expense was $34.2 million and $25.9 million for the three months ended September 30, 2013 and 2012, respectively, and was $124.6 million and $64.7 million for the nine months ended September 30, 2013 and 2012, respectively. The income tax provision consists of U.S. and Ghanaian income and Texas margin taxes.

 

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

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(In thousands)

 

Bermuda

 

$

(5,880

)

$

(2,316

)

$

(19,320

)

$

(8,735

)

United States

 

2,740

 

3,145

 

8,014

 

9,492

 

Foreign—other

 

(7,124

)

(11,156

)

40,664

 

(34,661

)

Income (loss) before income taxes

 

$

(10,264

)

$

(10,327

)

$

29,358

 

$

(33,904

)

 

Our effective tax rate for the three months ended September 30, 2013 and 2012 is (333)% and (251)%, respectively. For the nine months ended, September 30, 2013 and 2012, our effective tax rate is 424% and (191)%. The effective tax rate for the United States is approximately 42% and 43% for the three months ended September 30, 2013 and 2012, respectively, and 125% and 116% for the nine months ended September 30, 2013 and 2012, respectively. The high effective tax rates in the United States are due to the effect of tax shortfalls related to equity-based compensation. The effective tax rate for Ghana is approximately 36% and 39% for the three months ended September 30, 2013 and 2012, respectively, and 36% and 37% for the nine months ended September 30, 2013 and 2012, 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 2009 through 2012 and to Texas margin tax examinations for the tax years 2008 through 2012. In addition, the Company is open to income tax examinations for years 2004 through 2012 in Ghana.

 

As of September 30, 2013, 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 has not accrued any material amounts to date.

 

11. Net Income (Loss) Per Share

 

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

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(In thousands, except per share data)

 

Numerator:

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(44,488

)

$

(36,250

)

$

(95,210

)

$

(98,634

)

Less: Basic income allocable to participating securities(1)

 

 

 

 

 

Basic net income (loss) allocable to common shareholders

 

(44,488

)

(36,250

)

(95,210

)

(98,634

)

Diluted adjustments to income allocable to participating securities(1)

 

 

 

 

 

Diluted net income (loss) allocable to common shareholders

 

$

(44,488

)

$

(36,250

)

$

(95,210

)

$

(98,634

)

Denominator:

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Basic

 

377,654

 

373,448

 

376,509

 

371,140

 

Restricted stock awards and units(1)(2)

 

 

 

 

 

Diluted

 

377,654

 

373,448

 

376,509

 

371,140

 

Net income (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.12

)

$

(0.10

)

$

(0.25

)

$

(0.27

)

Diluted

 

$

(0.12

)

$

(0.10

)

$

(0.25

)

$

(0.27

)

 


(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

 

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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 (loss) 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 (loss) per common share calculation in periods we are in a net loss position.

 

(2)                                 We excluded outstanding restricted stock awards and units of 13.9 million and 17.1 million for the three months ended September 30, 2013 and 2012, respectively, and 13.9 million and 17.1 million for the nine months ended September 30, 2013 and 2012, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

 

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 consolidated financial statements; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

 

In June 2013, we signed a long-term rig agreement with a subsidiary of Atwood Oceanics, Inc. for the new build drillship “Atwood Achiever.” Currently under construction, the rig is scheduled for completion in June 2014 and expected to commence drilling operations in the second half 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.

 

The estimated future minimum commitments under this contract as of September 30, 2013, are:

 

 

 

Payments Due By Year(1)

 

 

 

Total

 

2013(2)

 

2014

 

2015

 

2016

 

2017

 

Thereafter

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Atwood Achiever drilling rig contract (3)

 

$

651,525

 

$

 

$

90,440

 

$

217,175

 

$

217,770

 

$

126,140

 

$

 

 


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

 

(2)                                 Represents payments for the period from October 1, 2013 through December 31, 2013.

 

(3)                                 Commitments calculated using a day rate of $595,000 and an estimated rig delivery date of August 1, 2014.

 

13. Subsequent Events

 

In October 2013, we entered into three farm-out agreements with BP plc (“BP”) covering three blocks in the Agadir Basin, offshore Morocco. Under the terms of the agreements, BP will acquire a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. BP will fund Kosmos’ share of the cost of one exploration well in each of the three blocks, subject to a maximum spend of $120.0 million per well, and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled in any block, BP will pay 150% of its share of costs subject to a maximum spend of $120.0 million per well. BP shall also pay $36.3 million for their share of past costs. Completion of the transactions is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interests will be 30.0%, 29.925% and 30.0% in the Essaouira, Foum Assaka and Tarhazoute Offshore blocks, respectively, and we will remain the operator.

 

In October 2013, we entered into a farm-out agreement with Capricorn Exploration & Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Contract Area, offshore Western Sahara. Under the terms of the agreement, Cairn will acquire a 20% non-operated interest in the exploration permits comprising the Cap Boujdour Contract Area. Cairn will pay 150% of its share of costs of a 3D seismic survey and one exploration well capped at $125.0 million. In the event the exploration well is successful, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. Additionally, Cairn will contribute $12.3 million towards our future costs. Completion of the transaction is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interest in the Cap Boujdour Contract Area will be 55.0% and we will remain the operator.

 

Drilling of the Akasa-2A appraisal well on the WCTP Block was completed in October 2013. The Akasa-2A appraisal well did not encounter oil or gas reserves sufficient to be utilized as a producing well. Accounting rules require that the costs associated with the Akasa-2A appraisal well be impaired, which are $11.5 million and included in exploration expenses in the accompanying consolidated statement of operations. We estimate we will incur an additional $8.9 million of related well costs, which will be expensed as incurred.

 

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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, 2012, 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 asset portfolio includes existing production and other major project developments offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara) 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

 

Debt

 

Our $2.0 billion commercial debt facility (“Facility”) provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in April 2013, expires on December 15, 2014 and the letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on December 15, 2014, outstanding borrowings will also be constrained by an amortization schedule. The final maturity date is March 29, 2018.

 

In September 2013, as part of the normal borrowing base determination process, the availability under the facility was reduced $89.6 million to $1.2 billion. As of September 30, 2013, borrowings under the Facility totaled $900.0 million, the undrawn availability under the Facility was $309.5 million and there were no letters of credit drawn under the 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 commitments or if commitments from new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. The fees associated with outstanding letters of credit issued will be 0.5% per annum. The LC Facility has an availability period which expires on June 1, 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of September 30, 2013, there were four outstanding letters of credit totaling $29.0 million under the LC Facility.

 

Ghana

 

We previously received an approval for the Phase 1A PoD of the Jubilee Field, and production from Phase 1A commenced in late 2012. The Phase 1A program includes the drilling of up to eight additional wells consisting of up to five production wells and three water injection wells. Four wells, three producers and one injector, are online. Program execution is expected to be completed in the latter part of 2014.

 

Drilling of the Akasa-2A appraisal well on the WCTP Block was completed in October 2013. We believe that the well successfully identified the down dip water contact associated with the Akasa-1 discovery as intended. Should the Akasa discovery progress to a development, the Akasa-2A appraisal well is expected to be utilized in the development as a water injector well. However, since the Akasa-2A appraisal well did not encounter oil or gas reserves sufficient to be utilized as a producing well, accounting rules require that the costs associated with the Akasa-2A appraisal well be impaired. As such, $11.5 million is included in exploration expenses in the accompanying consolidated statement of operations for the three and nine months ended September 30, 2013. We estimate we will incur an additional $8.9 million of related well costs, which will be expensed as incurred.

 

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Table of Contents

 

Cameroon

 

In July 2013, we informed the government of Cameroon that we do not intend to enter into the next phase of our petroleum contracts in Cameroon and expect to relinquish our rights to the blocks.

 

Ireland

 

In July 2013, Ireland granted us Frontier Exploration Licenses 1-13, 2-13, and 3-13 pursuant to Licensing Options 11/5, 11/7 and 11/8. We commenced a 3D seismic program of approximately 5,000 square kilometers over these blocks in July 2013, which was completed in October 2013.

 

Mauritania

 

In June 2013, we commenced a 3D seismic program of approximately 10,300 square kilometers over portions of Blocks C8 and C12 which is expected to be completed in the fourth quarter of 2013.

 

Morocco

 

In January 2013, we closed on an agreement to acquire an additional 37.5% participating interest in the Essaouira Offshore Block from Canamens Energy Morocco SARL, one of our block partners. Certain governmental approvals and processes are still required to be completed before this acquisition is effective.

 

In August 2013, final government approvals and processes were completed for the acquisition of the additional 18.75% participating interest in the Foum Assaka Block in the Agadir Basin offshore Morocco from Pathfinder, a wholly owned subsidiary of Fastnet, one of our block partners.

 

In October 2013, Kosmos executed a petroleum agreement with the Office National des Hydrocarbures et des Mines (“ONHYM”), the national oil company of the Kingdom of Morocco, covering the Tarhazoute Offshore block, to which the Company previously held certain exploration rights under a 2011 reconnaissance contract. Under the terms of the petroleum contract, the Company is the operator of the Tarhazoute Offshore block. ONHYM holds a 25% carried interest in the block through the exploration period. The initial exploration period will last for two years and six months and will commence from the date specified in the exploration permits, which have yet to be finalized with the Government of Morocco and ONHYM. The exploration period may be extended for additional exploration extension periods of two years and six months and three years respectively. In the event of commercial success, the Company has the right to develop and produce oil or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances. The petroleum contract is subject to customary government approvals.

 

We are filing our new petroleum contract for the Tarhazoute Offshore block as well as our existing petroleum contracts to which we are a party and which have not otherwise been previously filed as exhibits to this Quarterly Report on Form 10-Q.

 

In October 2013, we entered into three farm-out agreements with BP plc (“BP”) covering three blocks in the Agadir Basin, offshore Morocco. Under the terms of the agreements, BP will acquire a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. BP will fund Kosmos’ share of the cost of one exploration well in each of the three blocks, subject to a maximum spend of $120.0 million per well, and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled in any block, BP will pay 150% of its share of costs subject to a maximum spend of $120.0 million per well. BP shall also pay $36.3 million for their share of past costs. Completion of the transactions is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interests will be 30.0%, 29.925% and 30.0% in the Essaouira, Foum Assaka and Tarhazoute Offshore blocks, respectively, and we will remain the operator.

 

In October 2013, we entered into a farm-out agreement with Capricorn Exploration & Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Contract Area, offshore Western Sahara. Under the terms of the agreement, Cairn will acquire a 20% non-operated interest in the exploration permits comprising the Cap Boujdour Contract Area. Cairn will pay 150% of its share of costs of a 3D seismic survey and one exploration well capped at $125.0 million. In the event the exploration well is successful, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. Additionally, Cairn will contribute $12.3 million towards our future costs. Completion of the transaction is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interest in the Cap Boujdour Contract Area will be 55.0% and we will remain the operator.

 

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Table of Contents

 

Suriname

 

In August 2013, we completed a 2D seismic program of approximately 1,400 line kilometers over a portion of Block 42, outside of the existing 3D seismic survey.

 

Results of Operations

 

All of our production-related 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, 2013 and 2012, are included in the following table:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(In thousands, except per barrel data)

 

Sales volumes:

 

 

 

 

 

 

 

 

 

MBbl

 

1,912

 

1,985

 

5,847

 

3,913

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

215,169

 

$

222,375

 

$

636,648

 

$

450,360

 

Average sales price per Bbl

 

112.52

 

112.01

 

108.88

 

115.08

 

 

 

 

 

 

 

 

 

 

 

Costs:

 

 

 

 

 

 

 

 

 

Oil production, excluding workovers

 

$

13,026

 

$

16,936

 

$

39,145

 

$

33,595

 

Oil production, workovers

 

19,550

 

27,937

 

40,506

 

38,196

 

Total oil production costs

 

$

32,576

 

$

44,873

 

$

79,651

 

$

71,791

 

 

 

 

 

 

 

 

 

 

 

Depletion

 

$

56,094

 

$

61,913

 

$

169,163

 

$

123,256

 

 

 

 

 

 

 

 

 

 

 

Average cost per Bbl:

 

 

 

 

 

 

 

 

 

Oil production, excluding workovers

 

$

6.82

 

$

8.53

 

$

6.69

 

$

8.58

 

Oil production, workovers

 

10.22

 

14.07

 

6.93

 

9.76

 

Total oil production costs

 

17.04

 

22.60

 

13.62

 

18.34

 

 

 

 

 

 

 

 

 

 

 

Depletion

 

29.33

 

31.18

 

28.93

 

31.50

 

Oil production cost and depletion costs

 

$

46.37

 

$

53.78

 

$

42.55

 

$

49.84

 

 

The following table shows the number of wells in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of September 30, 2013:

 

 

 

 

 

Wells Suspended or

 

 

 

Actively Drilling or Completing

 

Waiting on Completion

 

 

 

Exploration

 

Development

 

Exploration

 

Development

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Ghana

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Cape Three Points

 

1

 

0.31

 

 

 

8

 

2.47

 

 

 

Deepwater Tano

 

 

 

 

 

1

 

0.18

 

 

 

TEN

 

 

 

 

 

12

 

2.16

 

 

 

Jubilee Unit

 

 

 

1

 

0.24

 

 

 

1

 

0.24

 

Total

 

1

 

0.31

 

1

 

0.24

 

21

 

4.81

 

1

 

0.24

 

 

24



Table of Contents

 

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

 

Three months ended September 30, 2013 compared to three months ended September 30, 2012

 

 

 

Three Months Ended
September 30,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

 

 

(In thousands)

 

Revenues and other income:

 

 

 

 

 

 

 

Oil and gas revenue

 

$

215,169

 

$

222,375

 

$

(7,206

)

Interest income

 

77

 

137

 

(60

)

Other income

 

133

 

725

 

(592

)

Total revenues and other income

 

215,379

 

223,237

 

(7,858

)

Costs and expenses:

 

 

 

 

 

 

 

Oil and gas production

 

32,576

 

44,873

 

(12,297

)

Exploration expenses

 

78,038

 

38,127

 

39,911