Kosmos Energy Ltd. (Form: 10-Q, Received: 11/03/2014 11:43:37)

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

Table of Contents

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.

Table of Contents

“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.

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 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.

Table of Contents

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.

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.

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.

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.

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.

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.

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

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

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

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).

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.

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.

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.

Table of Contents

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.

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.

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

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.

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 6 th 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.

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 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 6 th 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%.

Table of Contents

Senegal

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	—	—	—	—	9	2.78	—	—
TEN	—	—	—	—	—	—	14	2.38
Deepwater Tano	—	—	—	—	1	0.18	—	—
Total	—	—	1	0.24	10	2.96	15	2.62

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, 2014 compared to three months ended September 30, 2013

	Three Months Ended September 30,						Increase
	2014			2013			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	137,485		$	215,169		$	(77,684	)
Interest income	69			77			(8		)
Other income	882			133			749
Total revenues and other income	138,436			215,379			(76,943		)
Costs and expenses:
Oil and gas production	15,097			32,576			(17,479		)
Exploration expenses	21,334			75,607			(54,273		)
General and administrative	35,148			38,077			(2,929		)
Depletion and depreciation	36,959			58,367			(21,408		)
Amortization—deferred financing costs	2,593			2,786			(193		)
Interest expense	9,838			8,781			1,057
Derivatives, net	(40,407		)	7,585			(47,992		)
Restructuring charges	(46		)	—			(46		)
Other expenses, net	329			1,864			(1,535		)
Total costs and expenses	80,845			225,643			(144,798		)
Income before income taxes	57,591			(10,264		)	67,855
Income tax expense	38,468			34,224			4,244
Net income (loss)	$	19,123		$	(44,488	)	$	63,611

Oil and gas revenue. Oil and gas revenue decreased by $77.7 million during the three months ended September 30, 2014 as compared to the three months ended September 30, 2013, primarily due to a decrease in sales volumes, one and one-half liftings in 2014 compared to two in 2013, and a lower realized price per barrel. We lifted and sold approximately 1,443 MBbl at an average realized price per barrel of $95.26 during the three months ended September 30, 2014 and approximately 1,912 MBbl at an average realized price per barrel of $112.52 during the three months ended September 30, 2013.

Oil and gas production. Oil and gas production costs decreased by $17.5 million during the three months ended September 30, 2014, as compared to the three months ended September 30, 2013 primarily due to a reduction in well workover costs and non-routine operating costs. Our workover costs are related to performing workovers on our wells, which are performed on an as needed basis. We expect the amount of costs associated with workovers to fluctuate based on the activity level during each quarter.

Exploration expenses. Exploration expenses decreased by $54.3 million during the three months ended September 30, 2014, as compared to the three months ended September 30, 2013. The decrease is primarily due to $13.2 million of unsuccessful well costs for the Ghana Akasa-2 appraisal well and Cameroon — Sipo-1 exploration well and $59.9 million for seismic costs for Mauritania, Ireland, Morocco (including Western Sahara) and new ventures incurred during the three months ended September 30, 2013 compared to $20.0 million for seismic costs for Senegal, Mauritania, Morocco (including Western Sahara) and new ventures incurred during the three months ended September 30, 2014.

Depletion and depreciation. Depletion and depreciation decreased $21.4 million during the three months ended September 30, 2014, as compared with the three months ended September 30, 2013. The decrease is primarily due to depletion recognized related to the sale of one and one-half liftings of oil during the three months ended September 30, 2014, as compared to two liftings during the three months ended September 30, 2013. In addition, the depletion rate is lower during the three months ended September 30, 2014 due to an increase in proved reserves in the fourth quarter of 2013.

Derivatives, net. During the three months ended September 30, 2014 and 2013, we recorded a gain of $40.4 million and a loss of $7.6 million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.

Table of Contents

Income tax expense. The Company’s effective tax rates for the three months ended September 30, 2014 and 2013 were 67% and (333)%, respectively. The effective tax rates for the periods presented are impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such losses. Income tax expense increased $4.2 million during the three months ended September 30, 2014, as compared with September 30, 2013, primarily due to an increase in pre-tax income from our Ghanaian subsidiary.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

	Nine Months Ended September 30,						Increase
	2014			2013			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	678,635		$	636,648		$	41,987
Gain on sale of assets	23,769			—			23,769
Interest income	323			191			132
Other income	2,190			708			1,482
Total revenues and other income	704,917			637,547			67,370
Costs and expenses:
Oil and gas production	54,366			79,651			(25,285		)
Exploration expenses	57,652			194,384			(136,732		)
General and administrative	95,041			118,787			(23,746		)
Depletion and depreciation	152,883			175,578			(22,695		)
Amortization—deferred financing costs	7,938			8,269			(331		)
Interest expense	20,984			27,789			(6,805		)
Derivatives, net	(20,869		)	386			(21,255		)
Restructuring charges	11,758			—			11,758
Loss on extinguishment of debt	2,898			—			2,898
Other expenses, net	1,632			3,345			(1,713		)
Total costs and expenses	384,283			608,189			(223,906		)
Income before income taxes	320,634			29,358			291,276
Income tax expense	170,035			124,568			45,467
Net income (loss)	$	150,599		$	(95,210	)	$	245,809

Oil and gas revenue. Oil and gas revenue increased by $42.0 million during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, primarily due an increase in sales volumes, six and one-half liftings in 2014 compared to six in 2013 offset slightly by a lower realized price per barrel. We lifted and sold approximately 6,297 MBbl at an average realized price per barrel of $107.78 during the nine months ended September 30, 2014 and approximately 5,847 MBbl at an average realized price per barrel of $108.88 during the nine months ended September 30, 2013.

Gain on sale of assets. During the nine months ended September 30, 2014, we closed three farm-out agreements with BP plc. As part of the transaction, we received proceeds in excess of our book basis, resulting in a gain of $23.8 million.

Oil and gas production. Oil and gas production costs decreased by $25.3 million during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. The change is due a reduction in well workover costs and non-routine operating costs in the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, offsetting an increase in routine production costs due to incremental liftings in 2014 compared to 2013. Our workover costs are related to performing workovers on our wells, which are performed on an as needed basis. We expect the amount of costs associated with workovers to fluctuate based on the activity level during each period.

Exploration expenses. Exploration expenses decreased by $136.7 million during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013. The decrease is primarily due to $97.2 million of unsuccessful well costs and other related costs primarily related to the Cameroon Sipo-1 exploration well, the Ghana Sapele-1 exploration well and the Ghana Akasa-2 appraisal well and $84.9 million for seismic costs for Mauritania, Ireland, Morocco and new ventures incurred during the nine months ended September 30, 2013 compared to $48.6 million for seismic costs for Mauritania, Morocco, Senegal, Suriname and new ventures incurred during the three months ended September 30, 2014.

General and administrative. General and administrative costs decreased by $23.7 million during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013. The decrease from prior year is related to an increase in capitalized general and administrative costs and general and administrative costs incurred for the benefit of and allocated to exploration expense; and a decrease in professional fees and occupancy and general expenses partially offset by an increase in compensation and benefits.

Table of Contents

Depletion and depreciation. Depletion and depreciation decreased $22.7 million during the nine months ended September 30, 2014, as compared with the nine months ended September 30, 2013. The change is due to the increase in proved reserves in the fourth quarter of 2013, which reduced the depletion rate used for the nine months ended September 30, 2014, partially offset by an increase in depletion recognized related to the sale of six and one-half liftings of oil during the nine months ended September 30, 2014, as compared to six liftings during the nine months ended September 30, 2013.

Interest expense. Interest expense decreased $6.8 million during the nine months ended September 30, 2014, as compared with the nine months ended September 30, 2013, primarily due to a write-down of the deferred interest (reduction in interest expense) as a result of a decrease in the estimated effective interest rate based on the terms of the amended and restated Facility effective in March 2014 and a lower average outstanding debt balance during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013.

Derivatives, net. During the nine months ended September 30, 2014 and 2013, we recorded a gain of $20.9 million and a loss of $0.4 million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.

Restructuring charges. 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 non-cash expense related to awards granted under our LTIP.

Income tax expense. The Company’s effective tax rates for the nine months ended September 30, 2014 and 2013 were 53% and 424%, respectively. The effective tax rates for the periods presented are impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such losses. Income tax expense increased $45.5 million during the nine months ended September 30, 2014, as compared with September 30, 2013, primarily due to an increase in pre-tax income from our Ghanaian subsidiary.

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margin. We have historically met our funding requirements through cash flows generated from our operating activities and secured funding from issuances of equity and debt. In relation to cash flow generated from our operating activities, if we are unable to resolve issues related to the continuous removal of associated natural gas in large quantities from the Jubilee Field, and the production restraints caused thereby, then the Company’s cash flows from operations will be adversely affected. See “Item 1A. Risk Factors— section of this quarterly report on Form 10-Q and our annual report on Form 10-K

Significant Sources of Capital

Facility

In March 2014, the Company amended and restated the then existing commercial debt facility (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 of September 30, 2014, borrowings under the Facility totaled $500.0 million and the undrawn availability under the Facility was $1.0 billion.

Table of Contents

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

Corporate Revolver

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 commitments 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 the 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.

Table of Contents

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	%

Capital Expenditures and Investments

We expect to incur substantial costs as we continue to develop our oil and natural gas prospects and as we:

· execute our 2014 exploration and appraisal drilling program in our license areas;

· develop our discoveries that we determine to be commercially viable;

· purchase and analyze seismic and other geological and geophysical data to identify future prospects; and

· invest in additional oil and natural gas leases and licenses.

Table of Contents

We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating interests in our prospects, the reliance on joint venture partners to meet their obligations, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, and the availability of suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if one or more of our assumptions proves to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2014 Capital Program

Our estimate for the 2014 capital program is $575.0 million consisting of:

· approximately $400.0 million for developmental related expenditures offshore Ghana; and

· approximately $175.0 million for exploration and appraisal related expenditures, including new venture opportunities.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploration activities and drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and the prices we receive from the sale of these commodities, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

The following table presents our liquidity and financial position as of September 30, 2014:

	September 30, 2014
	(In thousands)
Cash and cash equivalents	$	600,626
Restricted cash	50,746
Senior Notes at par	300,000
Drawings under the Facility	500,000
Net debt	148,628

Availability under the Facility	$	1,000,000
Availability under the Corporate Revolver	300,000
Available borrowings plus cash and cash equivalents	1,900,626

Cash Flows

	Nine months ended September 30,
	2014			2013
	(In thousands)
Net cash provided by (used in):
Operating activities	$	372,234		$	281,349
Investing activities	(231,077		)	(240,950		)
Financing activities	(138,639		)	(115,296		)

Operating activities. Net cash provided by operating activities for the nine months ended September 30, 2014 was $372.2 million compared with net cash provided by operating activities for the nine months ended September 30, 2013 of $281.3 million. The increase in cash provided by operating activities in the nine months ended September 30, 2014 when compared to the same period in 2013 was primarily due to an increase in results from operations offset by a negative change in working capital items.

Investing activities. Net cash used in investing activities for the nine months ended September 30, 2014 was $231.1 million compared with net cash used in investing activities for the nine months ended September 30, 2013 of $241.0 million. The decrease in cash used in investing activities in the nine months ended September 30, 2014 when compared to the same period in 2013 was primarily attributable to proceeds from the sale of assets of $58.3 million offset by an increase in expenditures for oil and gas assets of $45.8 million during 2014.

Table of Contents

Financing activities. Net cash used in financing activities for the nine months ended September 30, 2014 was $138.6 million compared with net cash used in financing activities for the nine months ended September 30, 2013 of $115.3 million. The increase in cash used in financing activities in the nine months ended September 30, 2014 when compared to the same period in 2013 was primarily due an increase in payments on the Facility of $300.0 million and deferred financing costs associated with the amendment to the Facility and the Senior Notes offset by the net proceeds of $294.0 million on the Senior Notes issuance.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2014:

	Payments Due By Year(4)
	Total		2014(5)		2015		2016		2017		2018		Thereafter
	(In thousands)
Principal debt repayments(1)	$	800,000	$	—	$	—	$	—	$	—	$	—	$	800,000
Interest payments on long-term debt(2)	381,809		9,522		61,619		59,946		63,809		57,647		129,266
Operating leases	16,908		813		3,260		3,158		3,223		3,323		3,131
Atwood Achiever drilling rig contract(3)	554,855		54,740		163,625		176,120		146,370		—		—

(1) Includes the scheduled principal maturities for the Senior Notes and the Facility. The scheduled maturities of the Facility are based on the level of borrowings and the available borrowing base as of September 30, 2014. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2014, there were no borrowings under the Corporate Revolver.

(2) Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and the interest on the Senior Notes.

(3) Commitments calculated using a day rate of $595,000. 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.

(4) 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.

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

The following table presents maturities by expected maturity dates under the Senior Notes and the Facility. For the Senior Notes, the interest rate represents the contractual fixed rate that we are obligated to periodically pay on the debt as of September 30, 2014. For the Facility, the interest rates represent the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.

	October 1 Through December 31,			Years Ending December 31,															Liability Fair Value at September 30,
	2014			2015			2016			2017			2018			Thereafter			2014
	(In thousands, except percentages)
Fixed rate debt:
Senior Notes	$	—		$	—		$	—		$	—		$	—		$	300,000		$	(304,500	)
Fixed interest rate	7.88		%	7.88		%	7.88		%	7.88		%	7.88		%	7.88		%
Variable rate debt:
Facility(1)	$	—		$	—		$	—		$	—		$	—		$	500,000		$	(500,000	)
Weighted average interest rate(2)	3.41		%	3.72		%	4.76		%	5.68		%	6.28		%	7.19		%
Interest rate swaps:
Notional debt amount(3)	$	35,000		$	16,875		$	6,250		$	—		$	—		$	—		$	(629	)
Fixed rate payable	2.22		%	2.22		%	2.22		%	—			—			—
Variable rate receivable(4)	0.33		%	0.61		%	1.38		%	—			—			—
Notional debt amount(3)	$	35,000		$	16,875		$	6,250		$	—		$	—		$	—		$	(671	)
Fixed rate payable	2.31		%	2.31		%	2.31		%	—			—			—
Variable rate receivable(4)	0.33		%	0.61		%	1.38		%	—			—			—
Notional debt amount(3)	$	40,555		$	23,137		$	—		$	—		$	—		$	—		$	(318	)
Fixed rate payable	1.34		%	1.34		%	—			—			—			—
Variable rate receivable(4)	0.33		%	0.39		%	—			—			—			—

(1) The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of September 30, 2014. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2014, there were no borrowings under the Corporate Revolver.

(2) Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.

(3) Represents weighted average notional contract amounts of interest rate derivatives. In the final year of maturity, represents notional amount from January — June.

(4) Based on implied forward rates in the yield curve at the reporting date.

Table of Contents

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2014, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.

Critical Accounting Policies

We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations section in our annual report on Form 10-K, for the year ended December 31, 2013.

Cautionary Note Regarding Forward-looking Statements

This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:

· our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop our current discoveries and prospects;

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

· the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;

· projected and targeted capital expenditures and other costs, commitments and revenues;

· termination of or intervention in concessions, rights or authorizations granted by the governments of Ghana, Ireland, Mauritania, Morocco (including Western Sahara), Senegal or Suriname (or their respective national oil companies) or any other federal, state or local governments or authorities, to us;

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

· the ability to obtain financing and to comply with the terms under which such financing may be available;

· the volatility of oil and natural gas prices;

· the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;

· the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;

· other competitive pressures;

· potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental hazards;

· current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes ;

· cost of compliance with laws and regulations;

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

· environmental liabilities;

· geological, technical, drilling, production and processing problems;

· military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;

· the cost and availability of adequate insurance coverage;

· our vulnerability to severe weather events;

· our ability to meet our obligations under the agreements governing our indebtedness, including the indenture governing the Senior Notes ;

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

· the amount of collateral required to be posted from time to time in our hedging transactions;

· our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and

· other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our annual report on Form 10-K.

Table of Contents

The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.

We manage market and counterparty credit risk in accordance with policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Information and Note 10—Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the nine months ended September 30, 2014:

	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates			Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2013	$	(11,017	)	$	(2,734	)	$	(13,751	)
Changes in contract fair value	12,616			(209		)	12,407
Contract maturities	8,336			1,325			9,661
Fair value of contracts outstanding as of September 30, 2014	$	9,935		$	(1,618	)	$	8,317

Commodity Derivative Instruments

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of three-way collars, purchased puts and swaps with calls. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of September 30, 2014:

			Weighted Average Dated Brent Price per Bbl										Asset
Term	Type of Contract	MBbl	Net Deferred Premium Payable		Swap		Floor		Ceiling		Call		Fair Value at September 30, 2014(1)
2014:
October — December	Three-way collars	1,507	$	0.01	$	—	$	88.44	$	113.75	$	134.58	$	1,105
2015:
January — December	Three-way collars	4,230	$	0.46	$	—	$	87.43	$	110.00	$	133.82	$	2,312
January — December	Swaps with calls	2,000	—		99.00		—		—		115.00		6,410
2016:
January — December	Purchased puts	2,000	$	3.41	$	—	$	85.00	$	—	$	—	$	238

(1) Fair values are based on the average forward Dated Brent oil prices on September 30, 2014 which by year are: 2014—$94.51, 2015—$96.64 and 2016 — $96.23. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on October 28, 2014 market quotes by year are: 2014—$85.68, 2015—$88.59 and 2016—$90.53.

Table of Contents

At September 30, 2014, our open commodity derivative instruments were in a net asset position of $9.9 million. As of
September 30, 2014, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $35.9 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $45.8 million.

Interest Rate Derivative Instruments

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” section of our annual report on Form 10-K for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.

Interest Rate Sensitivity

At September 30, 2014, we had indebtedness outstanding under the Facility of $500.0 million, of which $389.4 million bore interest at floating rates. The interest rate on this indebtedness as of September 30, 2014 was approximately 3.4%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.1 million in interest expense per year on the Facility. We pay commitment fees on the $1.0 billion of undrawn availability under the Facility and on the $300.0 million of undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

As of September 30, 2014, the fair market value of our interest rate swaps was a net liability of approximately $1.6 million. If LIBOR changed by 10%, we estimate it would have a negligible impact on the fair market value of our interest rate swaps.

Item 4. Controls and Procedur es

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2014, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATIO N

Item 1. Legal Proceeding s

There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.

Item 1A. Risk Factor s

The risk factor below supplements the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2013 and in the “Item 1A. Risk Factors” section of our quarterly report on Form 10-Q for the quarter ended June 30, 2014.

Outbreaks of disease in the geographies in which we operate may adversely affect our business operations and financial condition.

Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease and may lack the resources to effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas, develop or produce our license areas by limiting access to qualified personnel, increasing costs associated with ensuring the safety and health of our personnel, restricting transportation of personnel, equipment, supplies and oil and gas production to and from our areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies.

An epidemic of the Ebola virus disease is currently ongoing in parts of West Africa. A substantial number of deaths have been reported by the World Health Organization (“WHO”) in West Africa, and the WHO has declared it a global health emergency. It is impossible to predict the effect and potential spread of the Ebola virus in West Africa and surrounding areas. Should the Ebola virus continue to spread, including to the countries in which we operate, or not be satisfactorily contained, our exploration, development and production plans for our operations could be delayed, or interrupted after commencement. Any changes to these operations could significantly increase costs of operations. Our operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment and oil and gas production (in the case of our producing fields). Such operations also rely on infrastructure, contractors and personnel in Africa. Several countries have announced travel bans to certain African countries. If bans are extended to the countries in which we operate, including Ghana, or contractors or personnel refuse to travel there, we could be adversely affected. If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow. In addition, should the Ebola epidemic spread to Ghana, access to the FPSO operating at the Jubilee Field could be restricted and/or terminated. The FPSO is able to operate for approximately six weeks without access to the mainland, but if restrictions extended for a longer period we and the operator of the Jubilee Field would likely be required to cease production and other operations until such restrictions were lifted.

Table of Contents

Item 2. Unregistered Sales of Equity Securities and Use of Proceed s

There have been no material changes from the information concerning the use of proceeds from our IPO discussed in the “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” section of our annual report on Form 10-K.

Issuer Purchases of Equity Securities

Under the terms of our Long Term Incentive Plan (“LTIP”), we have issued restricted shares and restricted share units to our employees. On the date that these restricted shares and restricted share units vest, we provide such employees the option to withhold, via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP, the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the withholding tax obligation owed by such grantee. The shares withheld from the grantees to settle their tax liability are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares withheld during the nine months ended, September 30, 2014 and the average price paid per share.

	Total Number of Share Withheld/Purchased	Average Price Paid per Share
	(In thousands)
January 1, 2014—January 31, 2014	—	$	—
February 1, 2014—February 28, 2014	7	10.34
March 1, 2014—March 31, 2014	—	—
April 1, 2014—April 30, 2014	1	10.99
May 1, 2014—May 31, 2014	923	10.46
June 1, 2014—June 30, 2014	23	10.48
July 1, 2014—July 31, 2014	1	11.10
August 1, 2014—August 31, 2014	—	—
September 1, 2014—September 30, 2014	—	—
Total	954	10.46

Item 3. Defaults Upon Senior Securitie s

None.

Item 4. Mine Safety Disclosure s

Not applicable.

Item 5. Other Informatio n.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K, other than as follows:

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, which added Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission (“SEC”) defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us (“control” is also construed broadly by the SEC).

We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the fiscal quarter ended September 30, 2014. In addition, except as described below, at the time of filing this quarterly report on Form 10-Q, we are not aware of any such reportable transactions or dealings by companies that may be considered our affiliates as to whether they have knowingly engaged in any such reportable transactions or dealings during such period. Upon the filing of periodic reports by such other companies for the fiscal quarter or fiscal year ended September 30, 2014, as the case may be, additional reportable transactions may be disclosed by such companies.

As of October 28, 2014, funds affiliated with The Blackstone Group (“Blackstone”) held approximately 25% of our outstanding common shares, and funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 31% of our outstanding common shares. We are also a party to a shareholders agreement with Blackstone and Warburg Pincus pursuant to which, among other things, Blackstone and Warburg Pincus each currently has the right to designate three members of our board of directors. Accordingly, each of Blackstone and Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended September 30, 2014.

Table of Contents

Disclosure relating to Warburg Pincus and its affiliates

Warburg Pincus informed us of (i) the information reproduced below (the “SAMIH Disclosure”) regarding Santander Asset Management Investment Holdings Limited (“SAMIH”), and (ii) the information reproduced below (the “EIG Disclosure”) regarding the Endurance International Group (“EIG”). Each of SAMIH and EIG are companies that may be considered affiliates of Warburg Pincus. Because we, SAMIH, and EIG may be deemed to be controlled by Warburg Pincus, we may be considered an “affiliate” of each of SAMIH and EIG, respectively, for the purposes of Section 13(r) of the Exchange Act.

SAMIH Disclosure:

Quarter ended September 30, 2014

“An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations (“NPWMD sanctions program”) , holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen for the nine months ended September 30, 2014. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. In the nine months ended September 30, 2014, the total revenue for the Santander Group in connection with the investment accounts was £65 and net profits were negligible relative to the overall profits of Banco Santander, S.A.

In addition, during the third quarter 2014, Santander UK identified two additional customers: a UK national designated by the U.S. under the NPWMD sanctions program who holds a business account, where no transaction have taken place. Such account is in the process of being closed. No revenue or profit has been generated. A second UK national designated by the US for reasons of terrorism held a personal current account and a personal credit card account in the third quarter 2014, both of which have now been closed. Although transactions have taken place on the current account during the reportable period, revenue and profits generated were negligible. No transactions have taken place on the credit card.”

The SAMIH Disclosure relates solely to activities conducted by SAMIH and do not relate to any activities conducted by us. We have no involvement in or control over the activities of SAMIH, any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of SAMIH with respect to transactions with Iran, and we have not participated in the preparation of the SAMIH Disclosure. We have not independently verified the SAMIH Disclosure, are not representing to the accuracy or completeness of the SAMIH Disclosure and undertake no obligation to correct or update the SAMIH Disclosure.

EIG Disclosure:

Quarter ended September 30, 2014

“On or around September 26, 2014, during a routine compliance scan of new and existing subscriber accounts, EIG or its affiliates discovered that Seyed Mahmoud Mohaddes (“Mohaddes”) was named as the account contact for a subscriber account (the “Subscriber Account”). Previously, on July 2, 2013, before Mohaddes had been designated as a SDN, the billing information for the Subscriber Account was updated to include Mohaddes. On September 16, 2013, the Office of Foreign Assets Control (“OFAC”) designated Mohaddes as a Specially Designated National (“SDN”), pursuant to 31 C.F.R. Part 560.304. EIG discovered Mohaddes when its routine compliance scan identified an attempt on or around September 26, 2014 to add Mohaddes, an SDN, as the account contact to the Subscriber Account. EIG blocked the Subscriber Account that day and reported the domain name registered to the Subscriber Account to OFAC as potentially the property of a SDN, subject to blocking pursuant to

Table of Contents

Executive Order 13599. Since September 16, 2013, when Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber Account for web hosting and domain privacy services. EIG ceased billing for the Subscriber Account. To date, EIG has not received any correspondence from OFAC regarding this matter.

On July 10, 2014, OFAC designated each of Stars Group Holding (“Stars”), and Teleserve Plus SAL (“Teleserve”), as SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG’s compliance review processes, they discovered that the domain names associated with each of Stars and Teleserve (the “Stars/Teleserve Domain Names”) were registered through our platform. EIG immediately took steps to suspend and lock the Stars/Teleserve Domain Names to prevent them from being transferred or resolving to a website, and they promptly reported the Domain Names as potentially blocked property to OFAC. EIG did not generate any revenue from the Stars/Teleserve Domain Names since they were added to the SDN list on July 10, 2014. To date, EIG has not received any correspondence from OFAC regarding the matter.

On July 15, 2014 during a compliance scan of all domain names on one of its platforms, EIG identified the domain name Kahanetzadak.com (the “Domain Name”), which was listed as an AKA of the entity Kahane Chai which operates as the American Friends of the United Yeshiva and was designated as a SDN on November 2, 2001 pursuant to Executive Order 13224. Since the Domain Name was transferred into one of EIG’s reseller’s customer’s account, there was no direct financial transaction between EIG and the registered owner of the Domain Name. The Domain name was suspended upon discovering it on their platform, and EIG will be reporting the Domain Name to OFAC as potentially the property of a SDN.”

The EIG Disclosure relates solely to activities conducted by EIG and do not relate to any activities conducted by us. We have no involvement in or control over the activities of EIG , any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of EIG with respect to transactions with Iran, and we have not participated in the preparation of the EIG Disclosure. We have not independently verified the EIG Disclosure, are not representing to the accuracy or completeness of the EIG Disclosure and undertake no obligation to correct or update the EIG Disclosure.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

Table of Contents

SIGNATURE S

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Kosmos Energy Ltd.
		(Registrant)

Date	November 3, 2014	/s/ W. GREG DUNLEVY
		W. Greg Dunlevy
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Table of Contents

INDEX OF EXHIBIT S

Exhibit Number		Description of Document
10.1*		Hydrocarbon Exploration and Production Sharing Contract for the Cayar Offshore Profond between the Republic of Senegal and Petro-Tim Limited and Societe des Petroles du Senegal dated January 17, 2012.

10.2*		Hydrocarbon Exploration and Production Sharing Contract for the Saint Louis Offshore Profond between the Republic of Senegal and Petro-Tim Limited and Societe des Petroles du Senegal dated January 17, 2012.

10.3*		Deed of Transfer between La Societe Des Petroles Du Senegal (Petrosen), Timis Corporation Limited and Kosmos Energy Senegal concerning the Hydrocarbons Exploration and Production Sharing Contracts and Joint Operating Agreements covering the Cayar Offshore and Saint Louis Offshore Permits dated August 25, 2014.

31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Furnished herewith.

Exhibit 10.1

THE REPUBLIC OF SENEGAL

One People — One Goal — One Faith

HYDROCARBON EXPLORATION AND PRODUCTION SHARING CONTRACT

CAYAR OFFSHORE PROFOND

Petro-Tim limited

Petrosen

TABLE OF CONTENTS

		Page

*GENERAL PROVISIONS*		2

ARTICLE 1	DEFINITIONS	2
ARTICLE 2	PURPOSE AND TERM OF THE CONTRACT	5
ARTICLE 3	RIGHTS OF THE CONTRACTOR IN THE IMPLEMENTATION OF THE OIL OPERATIONS	6
ARTICLE 4	GENERAL OBLIGATIONS OF THE CONTRACTOR IN THE CONDUCT OF THE OIL OPERATIONS	6

*TITLE II RESEARCH*		9

ARTICLE 5	TERM OF THE RESEARCH PERIOD - RENEWALS	9
ARTICLE 6	SURFACE RETURNS AND RELEASE	10
ARTICLE 7	RESEARCH PROJECT OBLIGATIONS	10
ARTICLE 8	SURFACE AREA RENTS	13
ARTICLE 9	EVALUATION OF A DISCOVERY	14

*TITLE III EXPLOITATION*		17

ARTICLE 10	TERM OF THE EXPLOITATION PERIOD	17
ARTICLE 11	PRODUCTION PROGRAMMES	18
ARTICLE 12	NATURAL GAS	18
ARTICLE 13	HYDROCARBON MEASUREMENT	19
ARTICLE 14	HYDROCARBON TRANSPORT	20
ARTICLE 15	LOCAL DEMAND FOR CRUDE OIL	21

*TITLE IV JOINT PROVISIONS REGARDING RESEARCH AND EXPLOITATION*		21

ARTICLE 16	ANNUAL WORKS SCHEDULE	21
ARTICLE 17	INSPECTION OF OIL OPERATIONS	22
ARTICLE 18	INFORMATION AND REPORTS	23
ARTICLE 19	PERSONNEL, TRAINING AND EQUIPMENT	25
ARTICLE 20	ABANDONMENT AND TRANSFER OF ASSETS UPON EXPIRATION	26

*TITLE V ECONOMIC AND TAX PROVISIONS*		28

ARTICLE 21	PRICE OF RAW PETROLEUM AND NATURAL GAS	28
ARTICLE 22	RECOVERY OF OIL COSTS AND PRODUCTION SHARING	29
ARTICLE 23	TAXATION RULES	32
ARTICLE 24	SHARE EQUITY OF PETROSEN	33
ARTICLE 25	ACCOUNTING AND VERIFICATION	34
ARTICLE 26	IMPORTS AND EXPORTS	36
ARTICLE 27	FOREIGN EXCHANGE	37
ARTICLE 28	PAYMENTS	38

*TITLE VI MISCELLANEOUS PROVISIONS*		38

ARTICLE 29	CONTRACTOR’S RIGHTS OF TRANSFER AND INSPECTION	38
ARTICLE 30	TERMINATION OF THE CONTRACT	40
ARTICLE 31	FORCE MAJEURE	40
ARTICLE 32	ARBITRATION AND EXPERTISE	41
ARTICLE 33	APPLICABLE LAW - STABILIZATION OF CONDITIONS	42

		Page

ARTICLE 34	NOTIFICATIONS	42
ARTICLE 35	OTHER PROVISIONS	43

*APPENDIX 1 DELINEATION OF THE CONTRACT AREA*		46

*APPENDIX 2 ACCOUNTING PROCEDURE*		47

ARTICLE 1	GENERAL PROVISIONS	47
ARTICLE 2	PRINCIPLES AND BASES FOR ALLOCATION OF THE OIL PRODUCER COSTS	48
ARTICLE 3	PRINCIPLES GOVERNING THE ALLOCATION OF COSTS FROM THE PROVISION OF SERVICES, MATERIALS AND EQUIPMENT USED IN THE OIL OPERATIONS	52
ARTICLE 4	AMORTIZATION OF FIXED ASSETS AND RESEARCH EXPENSES	54
ARTICLE 5	INVENTORIES	55
ARTICLE 6	FINANCIAL AND ACCOUNTING STATEMENTS	55

CONTRACT

BETWEEN

· the Republic of Senegal (hereinafter the “ State ”), represented for the purposes hereof by Mr. Karim WADE, Minister of State, Minister of International Cooperation, Air Transport, Infrastructure and Energy,

party of the first part,

AND

· PETRO-TIM LIMITED , a company governed by the laws of the Cayman Islands, with its head office located at P.O. Box 866 Anderson Square Building, KY1-11023, hereinafter called “PETRO-TIM”, and hereby represented by Mr. Wong Joon Kwang, Managing Chief Executive Officer, duly authorized to that end,

· SOCIÉTÉ DES PÉTROLES DU SÉNÉGAL , a company governed by the laws of Senegal, with its head office located at Dakar, Route du Service Géographique, Hann BP 2016, Senegal, hereinafter “PETROSEN”, and hereby represented by Mr. Ibrahima MBODJI, Managing Director, duly authorized to that end,

Hereinafter collectively referred to as the “ Contractor ”,

party of the second part,

WHEREAS

The discovery and the operation of hydrocarbons are prominent economic policy objectives within the territory of the Republic of Senegal;

The Contractor represents that it has the technical and financial capabilities to execute the Oil Operations authorized in accordance with this document and wishes to undertake the said Oil Operations within the framework of a production sharing contract, setting forth its rights and obligations;

Having regard to Act No. 98-05 dated 8 January 1998 containing the Oil Code setting forth the legal and tax system for research, operation and the transport of hydrocarbons and its implementing decree No. 98-810 of 6 October 1998;

NOW THEREFORE, THE FOLLOWING HAS BEEN MUTUALLY AGREED AND ORDERED:

CHAPTER ONE

GENERAL PROVISIONS

ARTICLE 1

DEFINITIONS

The terms defined in this article shall have the following meaning for the entire Contract and the other texts that may supplement or modify the same:

1.1. “Joint Operating Agreement” means the Agreement executed between the Parties constituting the Contractor, in accordance with Article 4.9 below, setting forth the respective rights, interests and obligations of the said Parties concerning the Contractual Area and determining the terms under which the Oil Operations shall be carried out, and the expenses and results associated therewith shall be allocated among the said Parties.

1.2. “Calendar Year” means a period of twelve (12) consecutive months, beginning on January first (1st) and ending on the following December thirty- first (31st).

1.3. “Contract Year” means a period of twelve (12) consecutive months, beginning on the Effective Date or the anniversary of said Effective Date.

1.4. “Budget” means the detailed cost estimate of the Oil Operations forecast in the Annual Works Programme.

1.5. “Contractor” means, collectively, PETRO-TIM LIMITED and PETROSEN and any entity to which an interest might be transferred pursuant to Articles 24 and 29 below.

1.6. “ Contract ” means this document and its appendices forming the Contract and any addition or modification to this document, receiving the approval of the Parties in accordance with the provisions of Article 35.3 below.

1.7. “ Oil Code ” means Law No. 98-05 dated 8 January 1998 establishing the legal and tax code for research, operation and the transport of hydrocarbons, and its implementing provisions.

1.8. “Oil Costs” means the entirety of the costs and expenses incurred by the Contractor within the framework of this Contract that are necessary according to industry rules in use in the international oil industry in performing the Oil Operations involving the Contract Area and determined according to the Accounting Procedure attached to this Contract as Appendix 2.

1.9. “Effective Date” means the effective date of the Contract, as defined in Article 35.3 below.

1.10. “Dollar” means the United States dollar.

1.11. “State” means the Republic of Senegal.

1.12. “CFA Franc” means a franc of the West African Monetary Union (UMOA).

1.13. “Natural Gas” means the dry and wet gas produced in isolation or together with the Crude Oil and any other gaseous component extracts from the wells.

1.14. “Associated Natural Gas” means the Natural Gas existing in a reservoir in a solution with Crude Oil or in the form of “gas-cap” in contact with the Crude Oil, and which is produced or may be produced in association with Crude Oil.

1.15. “Non-Associated Natural Gas” means Natural Gas excluding Associated Natural Gas.

1.16. “Marketable Deposit” means a geological entity filled with hydrocarbons, duly evaluated in accordance with the provisions in Article 9 below, and which, in accordance with the rules in use in the international oil industry, can be developed and produced under economic conditions for the Contractor.

1.17. “Hydrocarbons” means Crude Oil and Natural Gas.

1.18. “Minister” means at any time the Minister in charge of the sector of Oil Operations or his qualified representative.

1.19. “Ministry” means at any time the Ministry in charge of the sector of Oil Operations.

1.20. “Oil Operations” means all operations for the prospecting, research, evaluation, development, production, storage, transport and sale of the Hydrocarbons to the Delivery Point, including the treatment of Natural Gas, but excluding the refining and distribution of petroleum products.

1.21. “Party (Parties)” means the State and/or the Contractor.

1.22. “Operation Perimeter” means the portion of the Contract Area delineated by the perimeter of a Marketable Deposit established in accordance with the provisions of Article 10.1 below.

1.23. “Crude Oil” means: raw mineral oil, asphalt, ozokerite and any other liquid hydrocarbons at the natural state or obtained from Natural Gas by condensation or extraction, including condensates and Natural Gas liquids.

1.24. “PETROSEN” means Société des Pétroles du Sénégal and its successors and transferees.

1.25. “Abandonment Plan” means the plan for the demobilisation and abandonment of the facilities and infrastructures associated with the production of Hydrocarbons, in accordance with the provisions of Article 20.

1.26. “Delivery Point” means the F.O.B. point at the loading terminal of the Hydrocarbons in Senegal and/or any other point mutually agreed upon by the Parties.

1.27. “Annual Works Schedule” means the document describing the Oil Operations to be carried out in accordance with the provisions of Article 16 below.

1.28. “Total Commercial Production” means the total production of Crude Oil and Natural Gas obtained from the Exploitation Perimeter(s), less the quantities used for the purposes of the Oil Operations and any unavoidable losses.

1.29. “Affiliated Company” means any company that directly or indirectly controls or is controlled by a company referred to in Article 42 of the Oil Code or any company that directly or indirectly controls or is controlled by a company referred to in Article 42 of the Oil Code, it being understood that such control means the direct or indirect ownership by a company or any other entity of a percentage of stock or corporate shares of no less than 50%, that is sufficient to give rise to voting rights at the general stockholder meeting of another company or to give a determining power in the management of such other company.

1.30. “State Company” means a public establishment, a national company or a Senegalese company created in view of oil operations in which the State has a majority share equity.

1.31. “Third Party” means an entity other than an Affiliated Company.

1.32. “Contract Area” means the surface area defined in Appendix 1 of this Contract. The surface areas returned by the Contractor shall be considered as no longer comprising the Contract Area. On the other hand, the Operation Perimeter(s) shall form an integral part of the Contract Area during the time they are in effect.

ARTICLE 2

PURPOSE AND TERM OF THE CONTRACT

2.1. This Contract is a production sharing contract by which the State entrusts the Contractor with the provision of all necessary services for the research, and if applicable, the operation of Hydrocarbons which the Contract Area might enclose.

The Contractor shall act solely to carry out and perform the Oil Operations. It shall assign all technical, technological means, equipment and materials and all personnel necessary thereto.

The Contractor shall assume, at its own risk and expense, the entire responsibility for the implementation and the financing of the Oil Operations.

In the event of discovery of a Marketable Deposit in the Contract Area, the production of Hydrocarbons from the said Deposit shall be, for the entire period of the Operation with respect to this Contract, the object of a production sharing between the Parties in accordance with the provisions of Article 22 below.

2.2. This Contract specifically establishes the conditions under which the research and the operation of the Marketable Hydrocarbon Deposit shall be carried out along with the storage, transport, primary treatment, liquefaction, evacuation of the Hydrocarbons and related substances and/or products derived therefrom by means of separation or treatment, refining proper being excluded.

2.3. This Contract is entered into for the period of research, including its renewals and extensions, and for the operation period relating to each Marketable Deposit, respectively defined in Articles 5 and 10 below.

2.4. If, at the end of the research period, including its renewals and extensions, the Contractor has not notified the Minister of its decision to develop a Marketable Hydrocarbon Deposit in accordance with Article 10.1 below, this Contract shall end.

2.5. The expiration, release or termination of this Contract does not release the Contractor from its obligation with respect to this Contract created before or on the occasion of the said expiration, release or termination, which shall be executed by the Contractor.

ARTICLE 3

RIGHTS OF THE CONTRACTOR IN THE IMPLEMENTATION OF THE OIL OPERATIONS

3.1. In accordance with the provisions of applicable laws and regulations, in particular the Oil Code and the provisions of this Contract, the Contractor shall have the right:

a) to search for Hydrocarbons within the Contract Area and, if necessary, the Operation Perimeters, and to extract, store, transport, carry out the primary treatment and/or liquefaction, sell, export the Hydrocarbons and the related substances and/or products deriving therefrom via separation or treatment, refining proper being excluded, coming from deposits contained within the Operation Perimeters.

b) to access any place located within the Contract Area, so as to perform therein the Oil Operations.

c) to implement any facilities and all work and in a general manner, all deeds and operations necessary for the conducting of the Oil Operations;

d) to use water necessary for the Oil Operations, provided that such use does not damage the water supply of the inhabitants and the water points for livestock;

e) to use the rocks, sand, clay, gypsum, lime and other similar substances, necessary to the conducting of the Oil Operations.

3.2. Subject to the Minister’s authorization, which shall not unreasonably be withheld, the Contractor shall have the right to build at its own expense all facilities necessary to the Oil Operations and in particular, but not limited to, any roads, pipelines, storage facilities, port facilities, both inside and outside the Contract Area.

Said authorization of the Minister may be subject to the use by Third Parties of the surplus capacities of the said facilities, on condition that such use does not interfere with the Oil Operations and that said Third Parties pay a fair and equitable consideration to the Contractor.

ARTICLE 4

GENERAL OBLIGATIONS OF THE CONTRACTOR IN THE CONDUCT OF THE OIL OPERATIONS

4.1. The Contractor shall comply with the laws and regulations of the Republic of Senegal and strictly abide by the stipulations of this Contract.

4.2. The Contractor shall perform all works necessary for the implementation of the Oil Operations, according to the rules of the art in use in the international oil industry.

In particular, the Contractor shall take all necessary steps to:

a) ensure that all of the facilities and equipment used in the Oil Operations are in good operating condition and are properly maintained and repaired during the period of this Contract;

b) avoid that any Hydrocarbons, sludge or any other product used in the Oil Operations may be wasted and may pollute the underground water;

c) place Hydrocarbons that are produced in storage areas built for this purpose and not remove Crude Oil from storage in underground tanks, except temporarily in situations of emergency or with the prior authorization of the Minister;

d) ensure the protection of the environment, prevent accidents and limit the consequences thereof, and in particular, prevent, reduce and control the pollution of the environment and if applicable restore the sites and undertake the abandonment project upon completion of each Oil Operation under the conditions established in Article 20 below.

4.3. All work and facilities erected in the marine areas of Senegal under this Contract shall be:

a) constructed, indicated and marked with buoys so as to leave at all times and in total safety free passage for navigation;

b) fitted with navigational aids that shall be approved by the proper Senegalese authorities and maintained in good operating condition.

4.4. The Contractor shall in particular make it known when implementing the Oil Operation to take all necessary measures for the protection of the environment, in accordance with the provisions of the international agreements related to the pollution of sea water by Hydrocarbons and their implementing provisions.

4.5. The Contractor shall compensate and indemnify the State and any person in the event of damage that might be caused by the Oil Operations or damage that occurred due to the employees or officials of the Contractor during or on occasions of said Operations.

The State shall in no way be liable for any damage, accident or dispute related to the Oil Operations.

4.6. The Contractor shall sign and have its subcontractors sign all insurance policies in use in the international oil industry relating to the obligations and liabilities for which it is responsible and specifically the liability insurance policies with respect to third parties, property damage insurance policies to the property and the environment, and the insurance policies that might be required by the regulations in effect in the Republic of Senegal. The Contractor shall provide to the Minister the certificates proving the signing of said insurance policies; this communication in no way shall commit the responsibility of the State for the event in which, upon the occurrence of an accident, the guarantees or the amount of these insurance policies should prove to be insufficient.

4.7. In the event that the Contractor is comprised of several entities, the obligations and responsibilities of the latter by virtue of this Contract shall be joint and several, save for the contrary rules provided in particular pursuant to Article 24 below regarding the rights and obligations of PETROSEN.

4.8. The Contractor is responsible for opening, within three (3) months after the Effective Date, an office in the Republic of Senegal and for maintaining it during the term of this Contract; the said office shall specifically be provided with an agent having the authority to conduct the Oil Operations and to whom any notification regarding this Contract may be submitted.

4.9. The Contractor shall, before the date on which this Contract is signed, give the Minister notice of the entity designated as operator for the carrying out of the Oil Operations under the responsibility of the Contractor. It shall also submit for its approval, within thirty (30) days following the Effective Date, the joint operating agreement entered into among the entities composing the Contractor. Any change of operator shall receive the prior approval of the Minister that may not be unreasonably withheld when the new operator has the technical and financial capacities necessary for carrying out the Oil Operations.

TITLE II

RESEARCH

ARTICLE 5

TERM OF THE RESEARCH PERIOD - RENEWALS

5.1. The initial research period related to the Contract Area shall be two (2) Contract Years.

5.2. If the Contractor has complied with the project obligations as defined in Article 7 below for the current Research Period, the Contractor shall be granted, as a matter of law, by way of a decree, the renewal of the research period on two (2) occasions for an additional research period of three (3) Contract Years for the first renewal and two and a half (2.5) Contract Years for the second renewal period.

For each renewal, the Contractor shall submit, in accordance with the provisions of the Oil Code, a request to the Minister at least two (2) months before the expiration of the then current research period.

5.3. If, as of the expiration of the second renewal period, an evaluation project programme for a discovery of Hydrocarbons as indicated in Article 9 below is in the process of being implemented, the Contractor shall as a matter of law obtain, by decree, within the estimated surface area of the said discovery, an extension of the research period underway for the time necessary for the completion of the evaluation project, without however being able to exceed six (6) months.

In such event, the Contractor shall submit an extension request to the Minister at least thirty (30) days before the expiration of the second renewal period, and for this same period, the Contractor shall have fulfilled all project obligations defined in Article 7 below.

5.4. In accordance with the provisions of the Oil Code, the duration of the research time period shall also be extended, if necessary, by decree, in the event of discovery of Hydrocarbons for which the project evaluation programme has been executed but has not yet made it possible to declare the latter marketable; the extension period, the area covered and the conditions of such extension are set forth in Article 9 below.

ARTICLE 6

SURFACE RETURNS AND RELEASE

6.1. Upon the expiration of the initial research period, the Contractor shall return at least thirty percent (30%) of the initial surface of the Contract Area.

6.2. Upon the expiration of the first renewal period, the Contractor shall return at least twenty percent (20%) of the initial surface area of the Contract Area.

6.3. Pursuant to Articles 6.1. and 6.2. above:

a) the surface areas abandoned with respect to Article 6.5 below, plus the surface areas already covered by the Operation Perimeters shall be deducted from the surfaces to be returned;

b) the Contractor shall have the right to determine the extent, the form and the location of the research perimeter which it intends to keep. However, the portion returned shall be a simple geometric form, marked off by North/South, East/West lines or by natural limits;

c) drawing with an indication of the research perimeter that is being kept shall be attached to the renewal request.

6.4. Upon the expiration of the research period, the Contractor shall return the remaining surface area of the Contract Area, excluding any surfaces covered by Operation Perimeters.

6.5. The Contractor may, at any time, subject to prior notice of three (3) months with the exception indicated in Article 10.5, notify the Minister that it waives its rights over all or part of the Contract Area. In the event of partial release, the provisions of Article 6.3.b) above shall be applicable to the delineation of the returned perimeter.

In any event, no voluntary release during a research period will reduce the project obligations cited in Article 7 below for the research period underway or the amount of the corresponding parent company guarantee.

ARTICLE 7

RESEARCH PROJECT OBLIGATIONS

7.1. The Contractor shall begin the geological and geophysical work within three (3) months following the Effective Date.

7.2. During the initial research period cited in Article 5.1 above, the Contractor shall:

a) a) carry out at least two thousand five hundred (2,000) of 3-D seismic acquisitions with a minimum investment of eight million Dollars (USD 8,000,000);

7.3. During the first renewal period cited in Article 5.2. above, the Contractor shall carry out at least one (1) exploration drilling with a minimum investment of twenty million Dollars (USD 20,000,000);

7.4. During the second renewal period cited in Article 5.2. above, the Contractor shall carry out at least one (1) exploration drilling with a minimum investment of twenty million Dollars (USD 20,000,000);

7.5. Each of the exploration drillings provided for under this Agreement shall be carried out up to the minimum depth of three thousand five hundred (3,500) meters from the surface of the sea (hereinafter the “contractual minimum depth”).

However, such drill operations may be stopped at a lesser depth, if the continuation of the drilling, carried out in accordance with the rules of the art in use in the international oil industry is excluded for one of the following reasons:

a) the base is encountered at a depth less than the minimum contract depth;

b) continuation of the drilling presents a clear danger due to the existence of an abnormal layer pressure;

c) oil formations are encountered, the crossing of which requires the laying of piping for their protection not permitting the reaching of the minimum contract depth.

In the event that any of the above conditions is satisfied, the Contractor shall, before stopping the drill operation, obtain the prior authorization of the Minister with the assistance of PETROSEN, which may not be unreasonably withheld, and the hole shall be — in the event of approval — considered as having been drilled to the minimum contract depth. The ruling of the Minister shall be made known as soon as possible.

7.6. If the Contractor, during the first renewal period, either during the initial research period, or the first renewal period, implements a number of exploratory drill operations greater than the minimum drill obligations provided for in Articles 7.3. and 7.4. above, then the excess hole or holes could be postponed to the following research period or periods and could be deducted from the project obligations set forth for the said period or

periods, on condition that at least one exploration hole shall be carried out per renewal period.

7.7. Pursuant to Articles 7.2. through 7.6. above, the holes made within the framework of a project evaluation programme shall not be considered as exploration holes, and only one well per discovery shall be considered as being an exploration hole.

7.8. If, at the end of any research period, or in the case of total release or termination of the Contract, the research work conducted having not attained the minimum commitments undertaken in Articles 7.2. through 7.4. above, the Contractor shall pay the State, no later than the expiration of the research period in progress, a compensation equal to the unpaid balance of the work commitments projected for this period and calculated in accordance with the provisions of Article 7.9. below, failing which the State shall call up the bond provided for in Article 7.10. below.

Once payment has been made, the Contractor shall be deemed to have fulfilled its minimum project obligations with respect to Article 7 of this Contract; the Contractor may, except in the case of termination of the Contract for a major breach of Contract, continue to benefit from the Contract provisions and, in the event of an allowable claim, obtain the renewal of the research period.

7.9. If the Contractor does not carry out the work provided for in Articles 7.2 through 7.4. above, the compensation cited in Article 7.8. that the Contractor shall pay to the State, as payment for non-execution, shall be determined as follows:

a) if the works provided for in Article 7.2. a) have not been performed, an amount of eight million Dollars (USD 8,000,000);

b) if the works provided for in Article 7.3 have not been performed, or if the exploration drilling has not been completed up to the minimum contractual depth provided for in Article 7.5 above, an amount of twenty million Dollars (USD 20,000,000);

c) if the works provided for in Article 7.4 have not been performed, or if the exploration drilling has not been completed up to the minimum contractual depth provided for in Article 7.5 above, an amount of twenty million Dollars (USD 20,000,000).

7.10. On the Effective Date, the Contractor shall provide an irrevocable parent company guarantee securing the proper performance of the works and financial obligations under this Agreement, acceptable by the Minister, covering its minimum work obligations for the initial research period.

In the event of renewal of the research period, the Contractor shall also provide at the entry into effect of each renewal period a similar bond covering the minimum project obligations for the renewal period in question.

The amount of the guarantee shall be calculated on the basis of the amounts in Article 7.9. above.

Three (3) months after the completion of a seismic progamme or an exploration hole carried out to the minimum contract depth, the above- mentioned bond shall be, after notification to the Minister, adjusted so as to cover the minimum project obligations of the research period in progress remaining to be fulfilled, evaluated according to the provisions of the previous paragraph.

If, at the end of any research period, or in the event of total release or termination of the Contract, the research project having not attained the minimum commitments agreed to in this Article 7, the Minister shall have the right under the terms of Article 7.8 to call up the bond as compensation for the non-execution of the project commitments that the Contractor had signed.

ARTICLE 8

SURFACE AREA RENTS

8.1. The Contractor, no later than the first day of each Contract Year, shall pay the following surface area leasing amount:

a) five (5) Dollars per square kilometre and per year during the initial research period;

b) eight (8) Dollars per square kilometre and per year during the first renewal period;

c) fifteen (15) Dollars per square kilometre and per year during the second renewal period and during any extension provided for in Articles 5.3. and 5.4. above.

8.2. The surface area rents shall be determined for the entire year according to the extent of the Contract Area held by the Contractor as of the due date of said rents. In the event of a release during the Contract Year, no reimbursement of the already-paid rents shall be made.

8.3. The surface area rents shall be paid by the Contractor to PETROSEN which has been entrusted by the State with the carrying out of actions necessary for the promotion of the oil investments in Senegal.

ARTICLE 9

EVALUATION OF A DISCOVERY

9.1. If the Contractor discovers Hydrocarbons within the Contract Area, it shall immediately notify the Minister thereof and prepare, in accordance with the rules of the art in use in the international oil industry, the tests required to evaluate the Petroleum indicated during the drilling.

9.2. If the Contractor wishes to evaluate the above-mentioned discovery, it shall submit to the Minister within six (6) months following the notification of the discovery a project evaluation programme and the corresponding budget. The Minister’s approval shall not be unreasonably withheld.

9.3. The Contractor shall then execute the evaluation project of the discovery as diligently as possible in accordance with the established programme.

9.4. At the end of this evaluation project, which may not be extended beyond the research period cited in Article 5 above, including the renewals and any extensions, the Contractor shall provide to the Minister, within two (2) months, a report containing the technical and economic data on the discovered deposit which will establish, according to the Contractor, the marketable character of the said deposit. This report shall include in particular the following information:

· the geological and petrophysical information of the deposit;

· the estimated delineation of the extent of the deposit and the corresponding technical proof;

· the results from the project tests conducted or samplings taken;

· an estimate of the reserves and a preliminary economic study for placing the deposit into operation.

9.5. The deposit’s marketability shall be determined by the Contractor. If the Contractor concludes that the duly evaluated deposit is marketable, it shall also submit to the Minister, within six (6) months from completion of the evaluation project, a development and operation startup plan of the

Marketable Deposit in question, which shall in particular contain the following:

· the precise delineation and surface area of the requested Exploitation Perimeter, within the currently valid Contract Area for the Marketable Deposit in question;

· an estimate of recoverable reserves, proven and probable and of the production profile and a study on the Hydrocarbon recovery methods and the economic development of the Natural Gas;

· the description and the project features necessary for the exploitation startup of the Marketable Deposit, such as the number of wells, the facilities required for production, treatment storage and the transport of the Hydrocarbons;

· the schedule for implementing the above-mentioned project and the date forecasted for the production startup;

· an environmental impact study indicating any effects from the projected work on the environment, the conditions under which they satisfy the environment concerns and a preliminary plan of abandonment or restoration of the sites in question at the end of the exploitation;

· an estimate of development costs and the corresponding exploitation, and an economic study proving the marketable character of the Deposit.

Within three (3) months following the acceptance of the development plan and the exploitation startup, the Minister may propose revisions or modifications to the said plan and the provisions of Article 16.2 of the Contract shall apply mutatis mutandis [with the necessary changes] to the said development plan concerning its adoption within three (3) months after it is submitted.

9.6. If the Marketable Deposit extends beyond the limits of the Contract Area, the Minister may, if necessary, require that the Contractor exploit the said deposit in conjunction with the contractor of the adjacent contract area or areas according to the provisions of a so-called “unitization” agreement.

The Contractor shall submit to the Minister for his approval the development and exploitation startup plan of the Marketable Deposit prepared in association with the contractor of the adjacent contract area within six (6) months after the Minister has stated his requirements.

If the development and exploitation startup plan is not submitted to the Minister within the above-indicated time period, or if it was not adopted

by the Minister, the latter may prepare a development and exploitation startup plan in accordance with the rules of the art in use in the international oil industry. Said plan shall be adopted by the Contractor if the terms established by the Minister do not have the purpose of reducing the economic profitability of the Contractor as resulting from the Contract or imposing on the Contractor an investment significantly higher than that which he would normally have had to assume if he have had to ensure the development and startup of exploitation by itself.

9.7. The Minister can request the Contractor to abandon the surface delineating a discovery of Hydrocarbons, if the Contractor:

a) has not begun the evaluation project of the discovery within two (2) years after the date of notification to the Minister of said discovery mentioned in Article 9.1 above;

b) does not consider the deposit as being marketable within a time period of eighteen (18) months after the completion of the evaluation project, except in the case of application of the provisions of Article 9.8. below.

Any surface area thus returned shall be deducted from the surfaces to be returned by way of Article 6 above, and the Contractor shall lose any right over the Hydrocarbons that could be produced from this discovery.

9.8. If, at the end of the evaluation project, the Contractor establishes in the report mentioned in Article 9.4. above that the Hydrocarbon deposit covered by the discovery is not exploitable commercially in the immediate future but may become so, he may, upon request, obtain an extension of the research period involving the presumed extension of said deposit the purpose of which is to grant him a withholding period of said deposit measured from the date the signed report was submitted, such period being equal:

a) to three (3) years in the event of a discovery of a Crude Oil deposit;

b) to five (5) years in the event of a discovery of a non-associated Natural Gas deposit.

During said retention period, the Contractor shall deliver to the Minister within sixty (60) days after the end of each Calendar Year a report showing the marketability or lack thereof of the deposit in question. He shall also, if it is a non-associated Natural Gas deposit, update the market study of the potential outlets of the said Gas.

9.9. If required, the Contractor, may, according to the terms set forth by the Oil Code, obtain, during the research period, a temporary exploitation authorization, in particular to conduct long-term production testing.

At the end of the said testing, the Contractor shall supply to the Minister an evaluation report similar to that mentioned in Article 9.4 above, that will indicate the results and the interpretations of the tests and an estimate of the long-term production profile of the deposit and of the best possible mode of recovery.

TITLE III

EXPLOITATION

ARTICLE 10

TERM OF THE EXPLOITATION PERIOD

10.1. If a discovery of Hydrocarbons is found commercially exploitable, the Contractor shall, on the date the development and the exploitation startup plan is submitted for the Marketable Deposit in question, apply for and obtain by decree, in accordance with the provisions of the Oil Code, the authorization of exploitation with respect to the Exploitation Perimeter of the said Deposit granted for a duration of twenty-five (25) years and involving the extent of the Marketable Deposit within the Contract Area that is currently valid.

10.2. Upon the expiration of the period of twenty-five (25) years stipulated in Article 10.1. above, the exploitation period of the Exploitation Perimeter shall be renewed by decree, upon the request of the Contractor, for an additional period of ten (10) years, renewable at most once, on condition that the Contractor has fulfilled all of its contract obligations and proves that a commercial production based on the Exploitation Perimeter is still possible at the expiration of the initial period of exploitation or the first renewal.

10.3. The Contractor shall start the development works of a Marketable Deposit no later than six (6) months after the granting of the Exploitation Perimeter and shall pursue such works diligently.

10.4. In particular, the Contractor shall:

a) apply to the exploitation startup of a Marketable Deposit the cleanest possible methods in order to avoid losses of energy and industrial products;

b) ensure the preservation of the deposit and the best possible economic performance in Hydrocarbons;

c) conduct studies for assisted recovery as soon as possible and use such processes if they lead to an improvement of the ultimate recovery rate of Hydrocarbons;

d) periodically conduct tests and measures on each well in production so as to control the proper exploitation of the Marketable Deposit.

10.5. Any release request related, in whole or in part, to an Exploitation Perimeter submitted by the contractor with an advance notice of one (1) year will be favourably examined if it has satisfied all of its obligations and promises to execute any work which it might be ordered to do by the Minister in the interest of public safety, the preservation of deposits and underground water and the protection of the environment, in accordance with the rules of the art in use in the international oil industry.

The above-mentioned advance notice shall be accompanied by the list of measures that the Contractor undertakes to implement at the time of its release, and this release shall only become effective after the proper execution of the work that may have been ordered by the Minister.

ARTICLE 11

PRODUCTION PROGRAMMES

11.1. The Contractor undertakes to produce on a yearly basis reasonable quantities of Hydrocarbons from each Marketable Deposit according to the rules of the art in use in the international oil industry, mainly taking into consideration the rules of proper preservation of the deposits and the best possible recovery of the Hydrocarbon reserves under economic conditions.

11.2. In case of production, the Annual Works Schedule, mentioned in Article 16 below, which the Contractor must submit before 1 (1st) October of each Calendar Year, to the Minister, will include, for each Marketable Deposit, the production program and the corresponding budget prepared for the following Year.

11.3. The Contractor shall attempt to produce, during each Calendar Year, the quantities estimated in the production programme defined above.

ARTICLE 12

NATURAL GAS

12.1. All provisions of the Contract shall apply mutatis mutandis [with the necessary changes] to Natural Gas subject to the special provisions of this article.

12.2. No quantity of Associated Natural Gas that, according to the evaluation of the Contractor, could not be economically reinjected, or used in the Oil Operation, or treated for sale, may be burned by the Contractor without the prior approval of the Minister which may not be refused if the temporary burning of the Gas is in accordance with the rules of the art in use in the international oil industry.

In such event, the Contractor shall, except in cases of emergency, notify the Minister at least two (2) months in advance and provide the necessary proof showing in particular that all or part of this Gas cannot be usefully and economically used to improve the best possible economic rate of recovery of Crude Oil by reinjection in accordance with the provisions of Article 10.4 above or any other use that could normally be required.

12.3. If the Contractor:

a) decides to burn the Associated Natural Gas in accordance with the provisions of Article 12.2. above; or

b) decides not to exploit a discovery of Non-associated Natural Gas;

then the State shall have the right to exploit and remove the said Natural Gas, without paying any compensation to the Contractor. The State shall assume in such event if applicable all the additional costs necessary for the production, the treatment and the removal of the said Natural Gas.

12.4. If the Contractor considers the Natural Gas as commercially exploitable, it may in particular sell the Natural Gas that it produces to the State for the local consumption needs of the Republic of Senegal at competitive prices with other replacement products but also for other industry uses at prices suitable to the Parties.

ARTICLE 13

HYDROCARBON MEASUREMENT

13.1. The Contractor shall measure, at a point mutually agreed upon by the Parties, all of the Hydrocarbons produced, after extraction of water and related substances, by using, according to the approval of the Ministry, the equipment and measuring procedures in accordance with the methods in use in the international oil industry. The Ministry shall have the right to

examine these measures and to inspect the equipment and procedures used.

13.2. If, during the exploitation, the Contractor wishes to modify the said equipment and procedures, it shall obtain the prior approval from the Minister.

13.3. When equipment or procedures used have led to an overestimate or an underestimate of the quantities measured, the error shall be considered as existing since the date of the last calibration of the equipment, unless the contrary can be proven and the appropriate adjustment shall be implemented for the corresponding period.

ARTICLE 14

HYDROCARBON TRANSPORT

14.1. The Contractor shall have the right to transport or have transported the products of its exploitation to points of storage, treatment, loading or wholesale consumption, all the while maintaining ownership, under conditions established by the Oil Code.

14.2. The authorization for transport shall be granted under law, upon their request, either to the Contractor, or individually to each of the companies forming the Contract. The approval by the Minister of a pipeline project, as indicated in Article 39 of the Oil Code, may not be refused, if the project complies with the current regulations and makes it possible to ensure the transport of the products extracted under the best possible technical, economical and environmental conditions.

14.3. In the event of several discoveries of Hydrocarbons within the same geographical region, the Contractor may come to a friendly agreement with the other exploiting entities for the construction and/or common usage of pipeline installations making it possible to evacuate all or part of their respective productions. All protocols, agreements or contracts resulting therefrom shall be submitted for the prior approval of the Minister.

Absent an amiable agreement, the Minister may request that the Contractor and the other exploiting entities join forces for the construction and/or common usage, under the best possible technical and economic conditions of facilities or pipelines, on condition that this demand may not be either for reducing the economic profitability of the Contractor such as it results from this Contract or imposing a significant investment for the Contractor in particular greater than that which it would normally have

had to assume if it had had to ensure alone the implementation of the project.

ARTICLE 15

LOCAL DEMAND FOR CRUDE OIL

15.1. The Contractor assumes an undertaking as regards its production of Crude Oil in the Republic of Senegal to be sold to the State by priority, the share needed to satisfy the domestic consumption needs of the country, equal at a maximum to the percentage that the quantity of Crude Oil produced by the Contractor represents with respect to the total quantity of Crude Oil produced in the Republic of Senegal.

15.2. The Minister shall give no later than October first (1st) written notice of the quantity of Crude Oil that it chooses to buy, in accordance with this article, during the following Calendar Year. After the deliveries have been made to the State or to the beneficiary designated by the Minister, the deliveries shall be made in quantities reasonably equal and at regular time intervals during the said Year, according to the ways and means established by agreement of the Parties.

15.3. The Contractor shall sell the Crude Oil to the State at a price established in accordance with the provisions of Article 21 hereinbelow with regard to determining the “current international market price”. This price shall be payable in Francs CFA at the exchange rate with respect to the Dollar, published by the Central Bank as of the payment date established sixty (60) days after delivery.

TITLE IV

JOINT PROVISIONS REGARDING RESEARCH AND EXPLOITATION

ARTICLE 16

ANNUAL WORKS SCHEDULE

16.1. The Contractor shall submit to the Minister, within thirty (30) days following the Effective Date of the Contract, the Annual Works Schedule and the corresponding Budget for the Calendar Year in progress.

Three (3) months before the expiration of each Calendar Year, the Contractor shall submit to the Minister the Annual Works Schedule and the corresponding Budget forecast for the following Calendar Year.

The Annual Works Schedule and the corresponding Budget shall be subdivided among the various research, evaluation, development and production activities.

16.2. The Minister may not unreasonably reject the Annual Works Schedule and the corresponding Budget. However, the Minister may propose revisions or modifications to the Annual Works Schedule by making these known to the Contractor within thirty (30) days following the acceptance of this Programme.

In such event, the Minister and the Contractor shall meet as soon as possible to study the revisions and modifications requested and establish by mutual agreement the Annual Works Schedule and the corresponding Budget in their final form, in accordance with the rules of the art in use in the international oil industry. The date for adopting the Annual Works Schedule and the corresponding Budget shall be the date of the above-mentioned joint agreement.

If the Minister does not notify the Contractor of his wish to revise or modify the above documents, within the above-mentioned thirty (30) days, then the said Annual Works Schedule and the corresponding Budget shall be considered as being adopted by the Minister on the expiration date of the said time period.

16.3. The results derived during the carrying out of the project or any special circumstances might justify changes to the Annual Works Schedule. In such event, after notification to the Minister, the Contractor may carry out such changes on condition that the fundamental objectives of said Annual Works Schedule are not modified.

ARTICLE 17

INSPECTION OF OIL OPERATIONS

17.1. The Oil Operations shall be subject to the inspection of the State. Its duly- qualified officials shall have the right to monitor the Oil Operations and to inspect, at reasonable intervals, the facilities, equipment, materials, recordings and corresponding records of the Oil Operations.

17.2. Prior to any implementation, the Contractor shall give the Ministry notice of the Oil Operations such as geological or geophysical campaign, probing

or well testing, so that the qualified officials of the Ministry may be present at the said operations without however causing any delay in the normal progress of the operations.

The Contractor shall keep the Ministry informed of the progress of the operations, and if necessary inform it of any accidents that have occurred.

For the purposes of permitting the exercising of rights as indicated in Article 17.1 above, the Contractor shall provide to the representatives of the Ministry reasonable assistance regarding the means of transport and lodging, and expenses for transportation and lodging directly linked to the monitoring and to the inspection shall be at the expense of the Contractor.

17.3. The Ministry may demand that the Contractor carry out, at its own expense, all work deemed necessary to ensure the safety, hygiene and protection of the environment during the Oil Operations.

17.4. In the event that the Contractor decides to abandon a hole, it shall notify the Ministry thereof at least seventy-two (72) hours before the abandonment.

ARTICLE 18

INFORMATION AND REPORTS

18.1. The Contractor shall keep, in accordance with the rules of the art in use in the international oil industry, all data and information resulting from the Oil Operations and, in particular, the recordings, measurement and geophysical interpretation reports, geological reports, borehole loggings and drilling reports and tests, and shall supply a copy to the Ministry as soon as possible of all data, information, reports and interpretations, obtained or prepared during the Oil Operations.

All maps, sections, profiles and any other documents or geophysical or geological recordings shall be supplied to the Ministry on a transparent medium for subsequent reproduction and in digital form, if necessary.

The Contractor shall supply to the Ministry a representative portion of the core samples, drill cuttings, and samples of fluids produced during the tests or production trials.

Upon expiration, or in the event of a release or termination of the Contract, the original document, including the magnetic tapes, shall be transferred to the Ministry.

18.2. The Contractor shall supply to the Ministry the following periodical reports:

a) a daily report on the progress of the drilling and on the production, and a weekly report on the geophysical work in progress;

b) within fifteen (15) days following the end of each month, a monthly report on the Oil Operations underway;

c) within thirty (30) days following the end of the months of March, June, September and December, a quarterly report regarding the Oil Operations carried out during the past quarter and a detailed report of expenses incurred;

d) within sixty (60) days following the end of each Calendar Year, a report regarding the Oil Operations carried out during the past Calendar Year, and a detailed report of expenses incurred and a list of the personnel employed by the Contractor.

18.3. The Ministry may at any time access technical and economic files of the Contract with respect to the Oil Operations, of which at least one copy shall be kept in the Republic of Senegal.

The Contractor undertakes to supply to the Ministry upon its request, all reports, studies, recordings, measuring results, tests, trials, interpretations, documents and information enabling the monitoring of the execution of the Oil Operations.

18.4. All reports and information supplied to the Ministry by the Contractor shall be, if they bear the disclosure “Confidential”, considered as such during a period of three (3) years from the time they are obtained. The State may makes these documents known to any individual employed by it or working on its behalf. The above-mentioned confidentiality period may be increased if the Minister so deems necessary.

However, the Minister may use the information supplied by the Contractor for the purpose of preparing and publishing any report required by law and any report and study of general interest.

18.5. Notwithstanding the provisions of Article 18.4 above, the Minister may place any information in the public domain regarding any area on which the release, or withdrawal of the said rights or the termination of the Contract over the said area.

ARTICLE 19

PERSONNEL, TRAINING AND EQUIPMENT

19.1. The Contractor may, immediately from the start of the Oil Operations, employ on a priority basis, with equal qualifications, the citizens of the Republic of Senegal and contribute to the training of this personnel in order to enable their promotion to any positions as qualified workers, specialty officials, clerks and managers.

At the end of each Calendar Year, the Contractor shall prepare, in agreement with the Ministry, a recruitment plan and a training plan to achieve an increased and broader participation of the Senegalese personnel in the Oil Operations.

19.2. Particularly, in order to facilitate the employ of Senegalese personnel, the Contractor shall provide, in view of the satisfaction of its needs, for the training and the advanced training of its personnel employed for the Oil Operations. The Contractor shall also attempt to provide for the training and advanced training of the personnel of the Ministry and of PETROSEN.

The Contractor shall organize this training and advanced training, according to a plan established by mutual agreement with the Minister and the General Manager of PETROSEN, either within its company, or in other enterprises, by means of internships or exchanges of personnel, both in Senegal and abroad.

In addition, the Contractor shall support PETROSEN with the promotion of oil research and operations in Senegal.

For these purposes, the Contractor shall devote to the training plan of the Ministry’s personnel and that of PETROSEN a minimum of:

· Two hundred thousand Dollars (USD 200,000) per year during the research period; and

· starting from the granting of an Exploitation Perimeter, a minimum of three hundred thousand Dollars (USD 300,000) per Contract Year.

19.3. In addition, the Contractor shall earmark for the promotion of oil exploration and production in Senegal a minimum amount of one hundred thousand Dollars (USD 100,000) per Contract Year for the research period;

19.4. During the first Contract Year, the Contractor agrees to acquire for PETROSEN and in accordance with PETROSEN’s instructions, earth

science hardware and software and its updates over a period of five (5) years in the amount of One hundred and fifty-thousand Dollars (USD 150,000).

19.5. Foreign personnel employed by the Contractor and its subcontractors for the needs of the Oil Operations shall be authorized to enter and stay in Senegal for the required duration. The Ministry shall assist the Contractor for the issuance and the renewal of the administrative documents necessary for the entry and stay in the Republic of Senegal of said personnel and their families, in accordance with the current legislation.

ARTICLE 20

ABANDONMENT AND TRANSFER OF ASSETS UPON EXPIRATION

20.1. In accordance with the provisions of Article 9.5 above, the Contractor shall submit for approval to the Minister a preliminary plan of the abandonment or site restoration works at the end of operations (the “ Abandonment Plan ”); the Abandonment Plan of each relevant area shall be in line with generally accepted good workmanship in use in the international oil industry (the “ Abandonment Cost Estimates ”).

The Contractor shall be entitled to adjust the Abandonment Cost Estimates during the entire term of the Contract and shall indicate the amounts to be provided for in plus or minus in the annual report referred to in Article 18.2.b) above or in any other documents approved by an agreement between the Parties.

The Contractor shall open in its own name a bank account (the “ Bank Account ”) intended to receive, in Dollars or in any other convertible currency of its choosing, the amounts necessary to cover the Abandonment Cost Estimates (the “ Necessary Amounts ”). The Bank Account shall receive annual payments spread over the estimated life of each Commercial Deposit, in accordance with established principles governing the setting aside of provisions deductible for tax purposes.

The Bank Account may receive interest that shall be capitalized in order to contribute to the Necessary Amounts. In the event that the said Necessary Amounts appear to be higher than the Abandonment Cost Estimates, any amounts in excess shall be posted to the credit of the Oil Costs Accounts and/or added as exceptional profits.

The Amounts Necessary in order to cover the Abandonment Cost Estimates shall be recoverable Oil Costs and/or operating expenses recoverable for tax purposes.

20.2. Upon the expiration or the termination of the Contract, or in the case of surface area returns, the assets belonging to the Contractor and necessary for the Oil Operations in the area returned shall become the property of the State at no charge, unless they must be used by the Contractor for the exploitation of other Commercial Deposits located in Senegal. The transfer of ownership shall where applicable result in the terminating as a matter of law of any security interest or guarantee involving these assets, or that these assets comprise.

If the Minister decides not to use all or part of the said assets, he may demand that the Contractor removes them at the Contractor’s expense. However, the abandonment project shall be carried out in accordance with the Abandonment Plan.

20.3. During the Contract’s validity term, the probes acknowledged by joint agreement as unsuitable for the pursuit of research or the exploitation shall be taken up by the State, at the request of the Ministry, for the purposes of converting them into water wells. The Contractor shall then be responsible for leaving in place the pipes over the requested height and possibly the well-head and to perform the sealing of the probe in the requested area.

TITLE V

ECONOMIC AND TAX PROVISIONS

ARTICLE 21

PRICE OF RAW PETROLEUM AND NATURAL GAS

21.1. The unit sale price of the Crude Oil taken into consideration for the needs of the Contract shall be the actual F.O.B. sales price faithfully reflecting the current international market price as defined hereinbelow, at the Delivery Point.

21.2. The actual F.O.B. sales price, calculated each quarter of the Calendar Year, shall be the weighted average of the prices obtained by the Contractor and the State for sales contracts to Third Parties. Commissions paid at the time of sales to Third Parties shall not exceed the values in use in the international oil industry.

If such sales to Third Parties are not carried out during the quarter in question, or represent less than thirty percent (30%) of total sales, then the value shall be established by comparison with the “current international market price” during the quarter in question of the Crude Oil produced in Senegal and in the neighbouring producer countries, considering the differentials of quality, density, transport and payment.

“Current international market price” means a price enabling the Crude Oil sold to attain, at the sites of treatment or consumption, a competitive level equal to that practiced for Crude Oil of the same quality coming from other regions and delivered under comparable commercial conditions, both from the quantity standpoint as well as the destination and the use of the Crude Oil, taking into account market conditions and the type of contracts.

21.3. A commission chaired by the Minister, or his delegate and including representatives of the Administration and the representatives of the Contractor shall meet upon the request of its president, to establish, according to the stipulations of Article 21.2. above, the actual F.O.B. sales price of the Crude Oil produced, applicable to the quarter of the lapsed Calendar Year. The decisions of the commission shall be made unanimously.

21.4. If no decision is made by the commission within thirty (30) days after the end of the quarter of the Calendar Year in question, then the actual F.O.B. sales price of the Crude Oil produced shall be definitively established by

an internationally acknowledged expert, appointed by agreement by the Parties, or, lacking agreement, by the International Centre of Expertise of the International Chamber of Commerce.

The expert shall establish the price in accordance with the stipulations of Article 21.2 within twenty (20) days after his appointment. The costs of the expertise shall be equally shared by the Parties.

21.5. While waiting for the price to be established, the temporary actual F.O.B. sales price applicable for a quarter of the Calendar Year shall be the actual F.O.B. sales price of the previous quarter. Any necessary adjustment shall be implemented no later than thirty (30) days after the establishment of the actual F.O.B. sales price for the relevant quarter.

21.6. For the purposes of this Contract, the value of the Natural Gas sold or transferred to Third Parties or to the State shall be the actual price obtained by the contractor for the sale of the said Natural Gas.

As regards sales or transfer of Natural Gas other than those made to Third Parties or to the State, the relevant value shall be determined by agreement between the Minister and the Contractor, by taking into consideration inter alia the principles then in effect internationally for the marketing of the Natural Gas, the quality and the quantity of Natural Gas, and the price of the Senegalese Natural Gas sold to Third Parties under comparable market conditions.

ARTICLE 22

RECOVERY OF OIL COSTS AND PRODUCTION SHARING

22.1. In the event of Hydrocarbons production from the Contract Area, the Contractor shall have the right to receive free-of-charge, each Calendar Year, in view of the recovery of its Oil Costs, a maximum share of seventy- five percent (75%) of the Total Commercial Production of Crude Oil and Natural Gas.

If, during a Calendar Year, the value of the aforementioned maximum share of the Total Commercial Production, determined in accordance with the provisions of Article 21 above, is greater than the Oil Costs to be recovered during the said Year, then the Contractor shall receive only such lesser percentage of the production as is necessary and sufficient to recover the Oil Costs.

22.2. The Oil Costs shall be recoverable in the following manner:

a) With the exception of the Costs relating to fixed assets, as provided for in Article 4 of Appendix 2 to this Contract, the Oil Costs incurred during the implementation of the Oil Operations with respect to the Contract Area shall be recovered

· during the Calendar Year in which the Oil Costs were incurred;

· or during the Calendar Year of the production launch of the first Commercial Deposit of the Contract Area, if the latter year is after the Calendar Year in which the Costs were incurred.

b) The Oil Costs relating to fixed assets shall be recoverable at the annual amortization rate stipulated in Article 4 of Appendix 2 of this Contract.

The recovery of the Costs of the fixed assets corresponding to an Exploitation Perimeter shall begin:

· in the Calendar Year during which the fixed assets were implemented; or

· in the Calendar Year during which the production on said Exploitation Perimeter begins, if the latter year is after the Calendar Year in which the said fixed assets were implemented.

c) If the Oil Costs recoverable during any Calendar Year exceed in value the limit fixed in Article 22.1 above, then the surplus shall be brought forward to the following Calendar Year or Years until the recovery of said Oil Costs.

22.3. The Contractor shall receive each Calendar Year, by way of compensation, a percentage of the Total Commercial Production after deduction of the Hydrocarbon share intended for the recovery of the Oil Costs of the said Year, (hereinafter the “ Residual Production ”) in accordance with the provisions of Articles 22.1 and 22.2 above.

For this purpose, the Residual Production shall be shared by the State and the Contractor by way of the daily oil or gas production, in accordance with the following brackets:

· As regards the Crude Oil or gas equivalent :

Daily production (Barrels or gas equivalent)	State	Contractor
Less than 30,000	35%	65%
30,001 to 60,000	40%	60%
60,001 to 90,000	50%	50%
90,001 to 120,000	54%	46%
Above 120,000	58%	42%

22.4. The recovery of Oil Costs and the production sharing shall be established every quarter of the Calendar Year on a cumulative basis. If the production or the Oil Costs recoverable are not finally known as of the calculation date, estimates made based on the Annual Works Schedule and the Budget of the Calendar Year in question, as indicated in Article 16 above, shall be used. No later than two (2) months after the end of each Calendar Year, the amounts of the recovery of the Oil Costs and the production sharing for said Calendar Year shall be determined as well as the necessary adjustments.

22.5. In the event of Non-Associated Natural Gas Production, the Oil Costs corresponding to this production shall be recoverable on the basis of the latter production only, unless the Parties agree otherwise.

22.6. Pursuant to the provisions of this article, the value of the Hydrocarbons produced shall be that determined in Article 21 above.

22.7. Unless otherwise agreed, the Contractor shall acquire the ownership of the Hydrocarbons at the Delivery Point to which it is entitled under this Contract. However, the responsibility of the Contractor shall remain liable prior to the said transfer of ownership, in accordance with the provisions of Article 4 above.

22.8. The State shall decide whether the production share coming to it, after the recovery of the Oil Costs and the compensation of the Contractor, shall be taken in kind or converted into currency.

If the State decides to take its production share in kind, in all or in part, then the Minister shall give the Contractor notice of its decision at least three (3) months before each six-month period of the Calendar Year indicating the exact quantity it wishes to take during the following six- month period of the Calendar Year.

If the State decides to convert into currency its production share in all or in part, the Contractor shall pay to the State the value of this production calculated in accordance with the provisions of Article 21 above. This payment shall be made on a monthly basis within thirty (30) days following the end of the month to which the payment applies, and the Contractor shall acquire title to the said production share at the Delivery Point.

It is understood that the Contractor shall not enter into any sale commitment as regards the State’s production share of which the duration is more than six (6) months, unless with the written consent of the Minister.

ARTICLE 23

TAXATION RULES

23.1. The Contractor is subject to corporate taxation as provided for in the General Tax Code and the Oil Code.

The net profits derived by the Contractor from all of its Oil Operations in the territory of the Republic of Senegal as defined in the General Tax Code, unless otherwise stated in the Oil Code, are subject to a tax on corporations of twenty-five percent (25 %) calculated on the said net profits.

The Contractor shall maintain, per Calendar Year, in accordance with the regulations in effect in Senegal and the provisions of this Contract, a separate accounting of the Oil Operations which enables the establishing of a profits and losses account and a balance sheet indicating both the results of the said operations as well as the credit and liability items assigned thereto or directly relating thereto.

In the event that the Contractor is composed of several entities, the tax obligations of such entities are separate.

23.2. The Contractor and its Affiliated Companies under the protocols and agreements referred to in Article 8 paragraph 4 of the Oil Code shall benefit from the tax and customs advantages pursuant to Articles 48 and 49 of the Oil Code.

ARTICLE 24

SHARE EQUITY OF PETROSEN

24.1. Beginning from the Effective Date of this Contract, PETROSEN has in the Contract Area a share of the undivided interests of ten percent (10%) conferring upon it, in the proportion of its share equity, all rights and obligations of this Contract, subject to the provisions of this Article 24.

The share equity of PETROSEN indicated in the previous paragraph shall not entail for PETROSEN, during the entire duration of the research period, any participation in the expenses and charges incurred by the Contractor (including the expenses related to any indemnity in the event of non- compliance, the submission of a parent company bank bond, surface area rents and the training expenses pursuant to Articles 7.8, 7.10, 8, 19.2, 19.3 and 19.4 above respectively), the share of PETROSEN being borne by the other entities composing the Contractor, each on a prorated basis of its share equity percentage.

24.2. When the exploitation authorization with respect to an Exploitation Perimeter referred to in Article 10.1 becomes effective, PETROSEN shall have the option to increase its participation in the risks and profits associated with the Oil Operations in the said Exploitation Perimeter, in accordance with the following provisions:

a) within an Exploitation Perimeter, the share equity of PETROSEN may reach a maximum of twenty percent (20%), i.e. a maximum increase of ten percent (10%).

b) PETROSEN shall notify the Contractor of its decision to exercise its option to increase its share equity and the percentage of share equity chosen no later than six (6) months after the effective date of the authorization related to the Exploitation Perimeter;

c) the share equity of PETROSEN relating to an Exploitation Perimeter shall be effective from the effective date of the relevant exploitation authorization;

d) the entities, other than PETROSEN, composing the Contractor shall transfer to PETROSEN, each on a pro rata basis of its share equity as of that moment, a percentage of their share equity, of which the total shall be equal to the amount of increase in the share equity decided by PETROSEN;

e) PETROSEN shall, separately for each Exploitation Perimeter, have the right to exercise or not to exercise its option to increase its share equity.

24.3. Starting from the effective date of its participation indicated in Article 24.2.c). above, PETROSEN:

a) shall participate on a pro rata basis of its participation in the expenses corresponding to the Exploitation Perimeter in question;

b) shall possess and remove its fraction of the production obtained on the basis of the said Exploitation Perimeter.

PETROSEN shall not, by virtue of its share equity, be obligated to reimburse any part of the expenses incurred before the effective date of the exploitation authorization in relation to the Exploitation Perimeter, or to contribute to training and promotion expenses.

In the event that PETROSEN should exercise its option to increase its share equity pursuant to Article 24.2. above, it shall reimburse in Dollars to the Contractor, with no interest, on a pro rata basis of the increase of its share equity, the expenses incurred related to the Exploitation Perimeter in question between the effective date of the exploitation authorization and the date of its option exercise notice. Said reimbursement shall be made within sixty (60) days following the said notification date.

24.4. The respective rights and obligations of PETROSEN and the other entities composing the Contractor shall be established in the Joint Operating Agreement referred to in Article 4.9 above.

24.5. PETROSEN, on the one hand, and the other entities composing the Contractor, on the other, shall not be jointly and severally liable for the obligations resulting from this Contract.

Accordingly, PETROSEN shall be individually liable to the State for its obligations as provided for in the Contract.

The State at all times guarantees the execution of the obligations of PETROSEN under this Contract. Any failure of PETROSEN in the execution of any of its obligations shall not be considered as a failure of the Contractor and may under no circumstances be invoked by the State to terminate this Contract.

24.6. The State reserves the right to have its share under this Article 24 held by a State Corporation other than PETROSEN.

ARTICLE 25

ACCOUNTING AND VERIFICATION

25.1. The Contractor shall keep its accounting in accordance with the regulations in effect and according to the provisions of the Accounting Procedure established in Appendix 2 attached hereto which is an integral part of this Contract.

25.2. Accounting records and books shall be kept in French and denominated in Dollars. These records shall in particular be used to determine the recovery of the Oil Costs, the gross earnings, the operating costs, the net profits and the preparation of the Contractor earnings statement. For the record only, the profits and losses accounts and the balance sheets shall also be kept in Francs CFA.

25.3. Account records and books shall be materially proven by detailed documents proving the expenses and receipts of the Contractor in accordance with the provisions and obligations of the Contract.

25.4. The State, after informing the Contractor in writing, shall have the right to examine and check, by its own officials or experts of its choosing, the account records and books relating to the Oil Operations. It shall have five (5) years following the end of the year in question to conduct this examination or this verification and to submit to the Contractor any objection in relation to any discrepancies or errors observed during the examination or verification.

The State’s failure to make a claim within the above-mentioned five (5) years shall end any objection, dispute or claim on the part of the State for the financial year in question.

ARTICLE 26

IMPORTS AND EXPORTS

26.1. The Contractor shall have the right to import into the Republic of Senegal on its behalf or on behalf of its subcontractor any materials, equipment, machines, apparatuses, automobiles, airplanes, spare parts and consumable material necessary for the Oil Operations.

The above-mentioned goods shall be imported by the Contractor in accordance with the provisions of Article 49 of the Oil Code.

Furthermore, the expatriate employees and the families, hired to work in the Republic of Senegal on behalf of the Contractor or its subcontractors, shall have the right to import into the Republic of Senegal, when becoming settled therein, their personal effects, including their car.

26.2. The Contractor and its subcontractors undertake to carry out the imports defined above, only in so far as the said goods are not available in the Republic of Senegal in equal quantity, quality, price, time frame and payment conditions, save for any special technical emergencies or requirements submitted by the Contractor or its subcontractors.

The Contractor and its subcontractors undertake to grant preference to Senegalese enterprises for all construction, supply or service contracts with equal conditions in terms of quantities, quality, price, time fame and payment conditions.

For all contracts of a value greater than two hundred thousand (200,000) Dollars, the Contractor shall select its subcontractors by means of invitations to bid with Senegalese and foreign companies or by means of any other appropriate method in use in the international oil industry.

26.3. The Contractor and its subcontractors, and their foreign employees and their families, shall have the right to re-export, from the Republic of Senegal free of any exit fees and taxes, the goods imported pursuant to Article 26.1 above which would no longer be necessary for the Oil Operations, subject to the application of provisions provided for in Article 20 above.

26.4. The Contractor and its subcontractors shall have the right to sell, in the Republic of Senegal, on condition of informing the Minister in advance thereof, the goods that they imported when they are no longer necessary to the Oil Operations. In such event, it shall be the responsibility of the seller to fulfil all of the procedures required by the current regulations and to pay all fees and taxes applicable as of the transaction date, unless the above- mentioned goods are transferred to enterprises carrying out Oil Operations in the Republic of Senegal.

26.5. For the entire duration of the Contract, and subject to the provisions in Article 15 above, the Contractor shall have the right to export freely to the chosen destination for this purpose, free of any exit fees and taxes, the portion of Hydrocarbons to which the Contractor is entitled under the Contract.

26.6. All imports and exports under this Contract shall be subject to the procedures required by the current regulations concerning them, unless otherwise stipulated in Article 49 of the Oil Code.

ARTICLE 27

FOREIGN EXCHANGE

27.1. The Contractor shall be subject to the foreign exchange regulations of the Republic of Senegal. However, it is understood that the Republic of Senegal undertakes for the duration of this Contract to maintain in favour of the Contractor and its subcontractors the benefit of the following guarantees for the operations carried out within the framework of this Contract:

a) the right to contract loans abroad necessary for the execution of their activities in Senegal;

b) the right to collect and keep abroad all funds acquired or borrowed abroad, including earnings from sales, and to dispose thereof freely within the limit of the amounts exceeding the needs of their operations in Senegal;

c) the free movement of funds belonging to them free of any rights, taxes and commissions of any kind between Senegal and any other country;

d) the right to repatriate the capital invested within the framework of this Contract and to transfer their profits, in particular the interests and dividends;

e) and the free transfer of amounts owed, as well as the free receiving of amounts which are owed to them for any reason whatsoever, with the responsibility to make the declarations provided by the current regulations.

27.2. For the execution of its operations, the Contractor shall be authorized to practice the exchange of national currency and the foreign currencies convertible at exchange rates not less favourable for the Contractor than the rates applicable on the relevant day or than the rates generally

applicable in the Republic of Senegal to other firms, on the day of the operations.

27.3. Within thirty (30) days following the end of each Calendar Year quarter, the Contractor shall provide to the Minister in charge of finances, a report on the movements of funds related to the Oil Operations during the recently lapsed Quarter.

27.4. The expatriate employees of the Contractor shall have the right, in accordance with the current regulations in the Republic of Senegal, to the free exchange and to the free transfer to their country of origin of their savings on their salaries, as well as the contributions for retirement and savings plan paid by themselves or on their behalf, on condition that they have paid their taxes in the Republic of Senegal.

ARTICLE 28

PAYMENTS

28.1. All amounts owed to the State or to the Contractor shall be payable in Dollars or in any other convertible currency chosen by mutual agreement by the Parties.

28.2. In the event of a delay in a payment, the amounts owed shall bear interest at a rate equal to the LIBOR (London Interbank Offered Rate) plus two (2) percentage points per year, starting from the day on which they should have been paid.

TITLE VI

MISCELLANEOUS PROVISIONS

ARTICLE 29

CONTRACTOR’S RIGHTS OF TRANSFER AND INSPECTION

29.1. In accordance with the provisions of the Oil Code, the rights and obligations resulting from this Contract may not be transferred in part or in whole by any of the entities composing the Contractor without the prior approval of the Minister. The transfer shall involve the entirety of the rights and obligations relating to this Contract.

If, within sixty (60) days following the notification to the Minister of the transfer project accompanied by the transfer document, the Minister has not made known his reasoned opposition, then the said transfer shall be deemed approved by the Minister upon the expiration of the said time period.

Starting from the approval date, the transferee or transferees shall be acting in the capacity of the Contractor and shall fulfil the obligations imposed on the Contractor by the Oil Code and by this Contract to which they shall have adhered prior to the transfer.

In the event of a transfer to an Affiliated Company, the Minister shall authorize said transfer and may request, if applicable, that the parent company submit for the approval of the Minister a bond for the proper performance of the obligations under this Contract.

29.2. The Contractor also is responsible for submitting for the prior approval of the Minister:

a) any change of individual or any project which could possibly bring about, in particular by means of a new distribution of the corporate shares, a modification of the control of the Contractor or a company composing the Contractor. The distribution of the corporate capital, nationality of the majority shareholders, as well as the by-law provisions relating to the headquarters and the rights and obligations under the social titles shall be considered as elements of control of the Contractor. However, transfers of corporate shares to Affiliated Companies shall be free. Transfers of corporate equity shares to Third Parties shall only be subject to the approval of the Minister if they are intended to place in the hands of the latter more than twenty-five percent (25%) of the company’s capital.

b) any project for creating sureties encumbering the assets and facilities assigned to the Oil Operations.

The projects referred to in this Article 29.2 shall be made known to the Minister. If, within sixty (60) days after said notification, the Minister has not notified the Contractor of its reasoned opposition to the said project, they shall be considered as having been approved.

ARTICLE 30

TERMINATION OF THE CONTRACT

30.1. Pursuant to the Oil Code, this Contract may be terminated by the State in y of the following cases:

a) serious violation by the Contractor of the provisions of the Oil Code, or stipulations of this Contract, after official notification with no remedy within three (3) months;

b) delay of more than three (3) months as regards any payment to be made by the Contractor to the State, after a formal notice has not been heeded during a period of three (3) months;

c) after the startup of production on a Marketable Deposit, shutdown of its exploitation for one (1) year, without resumption of this exploitation six (6) months after receipt of a formal notice to that end;

d) the non-execution by the Contractor within the time period ordered of an arbitration ruling corresponding to this Contract;

e) or legal regulation or liquidation of the assets of the Contractor or its parent companies.

30.2. For the application of the provisions mentioned above, the Minister shall officially, by registered mail return receipt requested, ask the Contractor to comply with its obligations within the time periods established in paragraphs a) through d) above.

If the Contractor does not comply with this injunction within the applicable time periods, then this Contract may be terminated.

ARTICLE 31

FORCE MAJEURE

31.1. When one Party is incapable of performing its contract obligations, excluding payments which it owes, or can only perform the said obligations belatedly, due to an event of Force Majeure, the non-performance or delayed performance shall not be deemed violation of this Contract, on condition, however, that there is a link of cause and effect between the prevention and the event of Force Majeure invoked.

The Parties may rely on arbitration to determine, in particular, the nature of the alleged obstacle and its effect on the contractual obligation of the interested Party.

31.2. For the purposes of this Contract, may be deemed an event of Force Majeure any unforeseen event that is uncontrollable and beyond the

control of the Party invoking it, such as earthquakes, riots, insurrections, civil troubles, sabotage, wars or conditions attributable to war. The Parties intend that the term “Force Majeure” shall, to the greatest extent possible, be construed in conformance with the principles and uses of international law.

31.3. When a Party considers that it is prevented from performing any one of its obligations due to an event of Force Majeure, it must immediately notify the other Party thereof and indicate the reasons therefor.

It must also take all useful measures to ensure the normal resumption of the execution of the obligations affected as soon as possible, immediately from the cessation of the event of Force Majeure.

31.4. If, subsequent to an event of Force Majeure, the performance of any one of the obligations of the contract is deferred, then the duration of the resulting delay and the time period which could be necessary to repair any damage caused by the event of Force Majeure shall be added to the time period granted under the terms of the contract for the performance of the said obligation as well as the duration of the Contract.

ARTICLE 32

ARBITRATION AND EXPERTISE

32.1. In the event of any dispute arising between the State and the Contractor, concerning the interpretation or the performance of this Contract or any one of its provisions, the Parties shall attempt to resolve it out of court.

If the Parties are unable to settle the dispute out of court within three (3) months from its notification, they shall mutually agree that such a dispute shall be submitted to the International Centre for the Resolution of Investment-related Disputes (C.I.R.D.I.), for the purpose of its resolution by means of arbitration in accordance with the Agreement for the Resolution of Investment-related Disputes between Countries and Nationals of other Countries signed March 18, 1965 and ratified by Senegal according to the terms of Decrees 67-517 dated May 19, 1967 and which appeared in the Official Bulletin of the Republic of Senegal on June 10, 1967. The arbitration court shall be composed of three (3) arbitrators.

32.2. Arbitration shall take place in Paris (France). The arbitration procedure shall be conducted in French, and the applicable law shall be Senegalese Law.

The award of the court shall be handed down definitively and irrevocably; it shall be binding on the Parties and is immediately executable.

32.3. The Parties undertake to comply with any preservative measure ordered or recommended with majority ruling by the arbitration court constituted in accordance with the provisions of Article 32.1 above.

The introduction of an appeal in arbitration involves any suspension of effects regarding the object of the dispute. On the other hand, the execution by the Parties of their other obligations under this Contract shall not be suspended during the arbitration period.

32.4. In the event of difficulty in the performance of this Contract, the Parties shall mutually agree, in particular before any arbitration and lacking out-of- court settlement, to request from an expert to assist them in the out-of-court treatment of their dispute. Said expert shall be appointed by mutual agreement by the Parties or lacking agreement, by the International Expertise Centre of the International Chamber of Commerce in accordance with the technical expertise regulation thereof. The costs and fees of the expert shall be equally shared by the Parties (or at the expenses of the Contractor excluding PETROSEN until the startup of the commercial production).

ARTICLE 33

APPLICABLE LAW - STABILIZATION OF CONDITIONS

33.1. This Contract and the Oil Operations undertaken within the framework of said Contract are governed by the laws and regulations of the Republic of Senegal.

33.2. The Contractor shall be subject to the laws and regulations of the Republic of Senegal.

33.3. No provision may be applied to the Contractor the purpose of which is to directly or as a consequence thereof increase the charges and obligations deriving from the systems mentioned in Chapter 7 of the Oil Code, as these systems are defined by the legislation and the regulations in effect as of the date this Contract is signed, without prior agreement of the Parties.

ARTICLE 34

NOTIFICATIONS

34.1. All notices or other communications related to this Contract shall be forwarded in writing and shall be considered as having been submitted as soon as they have been carried or delivered under stamped recommended cover with acknowledgement of receipt or forwarded via telex or fax (with confirmation of receipt) to the choice of domicile indicated hereinbelow:

For the Republic of Senegal:

Minister of State:

Minister of International Cooperation, Art Transport, Infrastructures and Energy

Immeuble Tamaro

Rue Mohamed V x Jules Ferry

B.P. 23592 Dakar

Senegal

Tel.: (221) 33 849 88 43

Fax: (221) 33 849 88 15

Email: ME@micatti.gouv.sn

If to the Contractor

SOCIETE DES PETROLES DU SENEGAL

Managing Director

Route du Service Géographique, Hann

B.P. 2076 Dakar

Senegal

Tel.: (221) 33 839 92 98

Fax: (221) 33 832 18 99

Email: petrosen@petrosen.sn

If to PETRO TIM LIMITED

Boîte Postale 866 Anderson Square Building, Grand Cayman, KY111023

Suite 1109, Tai Yau Building, 181 Johnston Road, Wanchai, Hong Kong

Chief Executive Officer

Tel.: + 852 2961 2768

Fax: + 852 3011 3012

Email: edwongjk@gmail.com

34.2. The State and the Contractor may at any time change their authorized representative or modify the above choice of their address for notices, on condition of making it known with an advance notice of ten (10) days.

ARTICLE 35

OTHER PROVISIONS

35.1. The titles included in this Contract are inserted for purposes of convenience and of reference and in no way define, or limit or outline the scope or the purpose of the Contract, or any one of its clauses.

35.2. Appendices 1 and 2 attached hereto are an integral part of this Contract.

35.3. This Contract can only be modified in writing and by mutual agreement by the Parties.

35.4. Any waiver by the State of the performance of any obligation of the Contractor shall be recognized by this Contract.

35.5. The Effective Date shall be the date of the decree of approval of this Contract.

IN WITNESS WHEREOF , the Parties to this Contract have mutually agreed to sign the said Contract in five (5) copies and to submit it to the recording procedure at no cost.

Dakar, 17 January 2012

For the Contractor:

PETRO-TIM LIMITED		PETROSEN

/s/ M Wong Joon KWANG		/s/ Mr Ibrahima MBODJI
M Wong Joon KWANG		Mr Ibrahima MBODJI

For the Republic of Senegal

Minister of State

Minister of International Cooperation, Air Transport, Infrastructure and Energy

	/s/ M. Karim WADE
	Mr. Karim WADE

	For Approval

	THE PRESIDENT OF THE REPUBLIC

	/s/ H.E. Abdoulaye WADE
	H.E. Abdoulaye WADE

For Approval

APPENDIX 1

DELINEATION OF THE CONTRACT AREA

CAYAR OFFSHORE PROFOND

The total surface area is deemed equal to 7,895 square kilometres

Block’s coordinates

Point	Longitude	Latitude
A	17°25’00’’ W	15°25’00’’ N
B	17°25’00’’ W	15°00’00’’ N
C	17°40’00’’ W	15°00’00’’ N
D	17°40’00’’ W	14°45’00’’ N
E	18°30’00’’ W	14°45’00’’ N
F	18°30’00’’ W	15°25’00’’ N

APPENDIX 2

ACCOUNTING PROCEDURE

ARTICLE 1

GENERAL PROVISIONS

1.1. Purpose

This Accounting Procedure shall be followed and respected in the execution of the Contract obligations to which it is attached.

The object of this Accounting Procedure is to establish the rules and methods of accounting for the determination of the costs and expenses incurred by the Contractor and necessary, in accordance with the rules of the art in use in the international oil industry, for Oil Operations (hereinafter called “Oil Costs”).

1.2. Accounts and allocations

The Contractor shall record separately in different accounts all transactions with respect to Oil Operations and shall continuously keep accounts, books and records, distinguishing in particular:

· research expenses;

· evaluation expenses according to discovery;

· if necessary, according to Exploitation Perimeter:

· development and transport expenses of the production;

· current exploitation and transport expenses of the production;

· abandonment expenses;

· financial fees;

· general and administrative expenses.

The accounts, books and records of the Contractor shall be kept following the rules of the accounting schedule in effect in Senegal and the practices and methods in use in the international oil industry.

In accordance with the provisions of Article 25.2 of the Contract, the accounts, books and records of the Contractor shall be kept in French and denominated in Dollars.

Whenever it is necessary to convert into Dollars the expenses and receipts paid or received in any other currency, they shall be evaluated based on the exchange rate quoted on the exchange markets in Paris, according to the modalities established by mutual agreement.

All profits or losses resulting from the exchange of currency at the time of the transactions covered by this Contract shall be debited or credited to the account of the Oil Costs.

1.3. Interpretation

The definitions of the terms included in this Appendix 2 are the same as the corresponding terms in the Contract.

In the event there is a conflict between the provisions of this Accounting Procedure and that of the Contract, this one shall prevail.

1.4. Modifications

The provisions of the Accounting Procedure can be modified by mutual agreement by the Parties.

The Parties mutually agree that if one of the provisions of the Accounting Procedure should be inequitable with regard to one Party, they shall in good faith modify the provision in question to even out any inequality.

ARTICLE 2

PRINCIPLES AND BASES FOR ALLOCATION OF THE OIL PRODUCER COSTS

The Contractor shall keep a detailed account of the Oil Costs in which the Oil Costs borne for Oil Operations shall be posted and from which the following expenses and costs shall be debited:

2.1. Personnel expenses

All payments made or expenses incurred to cover the fixed salaries of employees of the Contractor and its Affiliated Companies directly assigned, either part-time or full- time, to the Oil Operations in the territory of the Republic of Senegal, including the legal and social charges and all additional charges or expenses

provided by individual or collective agreements in accordance with the administrative regulations of the Contractor.

2.2. Buildings

Construction, maintenance costs and related expenses including the leasing amount paid for all offices, houses, warehouses, and buildings, including the residences and recreation centres for employees and the costs of equipment, furnishings and fittings necessary for the use of such buildings required for the execution of the Oil Operations.

2.3. Materials, equipment and leasing amounts

Costs of the equipment, materials, machines, articles, furnishings and facilities bought or furnished for the needs of the Oil Operations, as well as the leasing amounts or compensations paid or incurred for the use of all equipment and facilities necessary to the Oil Operations, including equipment belonging to the Contractor.

2.4. Transportation

Transportation of the employees, equipment, materials and supplies within Senegal, as well as between Senegal and other countries, necessary for the Oil Operations. The transportation costs of the employees shall include the moving costs of the employees and their families paid by the Contractor in accordance with the policy established by the latter.

2.5. Services rendered by the subcontractors

The costs for the provision of services rendered for the needs of the Oil Operations by the subcontractors, consultants, expert advisors as well as all costs related to services rendered by the State or any other Senegalese authority.

2.6. Insurance policies and claims

Premiums paid for insurance policies that it is customary to underwrite for the Oil Operations needing to be implemented by the Contractor and all expenses incurred and paid for settlement of all losses, claims compensation and other expenses, including the legal services expenses not recovered by the policy holder and the expenses deriving from legal decisions.

If, after the approval of the Minister, no insurance policy has been undersigned for a particular risk, all expenses incurred and paid by the Contractor for settlement of all losses, claims, compensations, legal decisions and other expenses.

2.7. Legal expenses

All expenses related to the conduct, examination and the settlement of disputes of claims arising due to the Oil Operations, or those expenses necessary to protect or recover goods acquired for the needs of the Oil Operations, including in particular legal fees, court or investigation costs, and amounts paid by way of settlement or balance of such disputes or claims. If such actions must be conducted by the legal department of the Contractor, a reasonable compensation shall be included in the Oil Costs, which shall under no circumstances exceed the cost of the provision of such service normally practiced by a Third Party.

2.8. General and administrative expenses (“General Expenses”)

2.8.1. The General Expenses in the Republic of Senegal correspond to the retirement and personnel expenses of the Contractor serving the Oil Operations in the Republic of Senegal of which the work time is not directly assigned to the latter and the maintenance and operating costs of a general and administrative office and the auxiliary offices in the Republic of Senegal necessary for the Oil Operations.

2.8.2. The Contractor shall add a reasonable amount by way of General Expenses abroad necessary for the implementation of the Oil Operations and supported by the Contractor and its Affiliated Companies, the said amount being determined as a function of the annual amount of the Oil Costs (excluding financial fees and General Expenses) in the following manner:

a) for the range up to three million (3,000,000) Dollars per year: three percent (3%);

b) for the range between three million (3,000,000) Dollars and six million (6,000,000) Dollars per year: two percent (2%):

c) for the range between six million (6,000,000) Dollars and ten million (10,000,000) Dollars per year: one percent (1%);

d) for the range over ten million (10,000,000) Dollars per year: zero point five percent (0.5%).

2.9. Financial expenses

The interest and banking fees pertaining to the capital placed by Third Parties at the disposal of the Contractor to cover a fraction of the investment costs for development of the Commercial Deposits and transport of their production to Senegal to the Delivery Point corresponding to the fixed assets, in so far as they do not exceed the normal rates in use on the international financial markets for similar-type loans; as well as, notwithstanding Article 8.2 of the General Tax Code, the interest and banking fees used for associates or the Affiliated Companies by way of amounts that they place at the disposal of the Contractor in addition to their capital share, if these amounts are assigned to cover a reasonable co- payment of the development investment costs of the

Commercial Deposits and transport of their production to Senegal to the Delivery Point corresponding to fixed assets and if the interest rates do not exceed the rates mentioned above. Debts incurred abroad shall be reported beforehand to the Minister.

2.10. Provisions for abandonment costs

Provisions for abandonment costs set aside in accordance with the provisions of Article 20.1 of the Contract.

2.11. Other expenses

All expenses incurred by the Contractor and necessary for the conducting of the Oil Operations, other than the expenses covered and regulated by the previous provisions in Article 2 of this Appendix 2, and other than expenses, fees or losses not deductible for the determination of the profit subject to taxation on corporations in accordance with the General Tax Code or not capable of being allocated to the account of Oil Costs pursuant to Article 2.12 hereinbelow.

2.12. Expenses that cannot be allocated to the Oil Costs account

Expenses that are not directly necessary for the implementation of the Oil Operations, and the expenses excluded by the provision of the Contract or this Accounting Procedure as well as the regulations in effect in the Republic of Senegal, cannot be allocated to the Oil Costs account and are therefore not recoverable.

In particular, these expenses include:

a) expenses related to the period before the Effective Date;

b) all expenses related to the operations carried out beyond the Delivery Point, such as transport and marketing costs;

c) financial fees related to the financing of the Oil Operations for research, evaluation and exploitation and those related to the financing of the development costs and transport of the production to the Delivery Point exceeding the limits included in Article 2.9 above.

On the other hand, the provisions deductible from the net profit by way of taxation on corporations (excluding the provisions for abandonment costs included in Article 2.10 above) cannot be allocated to the Oil Costs account due to the definition of the latter.

2.13. Sums brought to the credit of the Oil Costs Account

In particular defined as credits to the Oil Costs to be recovered are the following earnings and products:

a) earnings from the marketing of the quantity of Hydrocarbons available to the Contractor, in accordance with Article 21.1 of the Contract, by way of recovery of Oil Costs;

b) all other earnings or products linked to the Oil Operations, in particular those from:

· the sale of related substances:

· all services rendered to Third Parties using the facilities assigned to the Oil Operations, in particular treatment, transport and storage of products for Third Parties in these facilities;

· the transfer of assets of the Contractor, and the transfer of all or part of the rights and obligations of the Contractor pursuant to Article 29 of the Contract.

ARTICLE 3

PRINCIPLES GOVERNING THE ALLOCATION OF COSTS FROM THE PROVISION OF SERVICES, MATERIALS AND EQUIPMENT USED IN THE OIL OPERATIONS

3.1. Technical Services

A reasonable rate shall be applied for technical services rendered by the Contractor or by its Affiliated Companies in relation to the Oil Operations executed within the framework of this Contract, such as gas, water or bore sample analyses, and any other test and analysis, on condition that such rates do not exceed those normally applied to similar services provided by service companies and independent laboratories.

3.2. Purchase of materials and equipment

The materials and equipment purchased that are necessary to the Oil Operations shall be allocated to the Oil Costs account on the basis of the “Net Cost” borne by the Contractor.

The “Net Cost” shall include the purchase price (deduction of any discounts and rebates obtained) and the elements such as export commissions or unloading and licensing fees and charges related to the supply of materials and equipment, as well as any losses in transit which are not recovered by insurance.

3.3. Use of equipment and facilities belonging to the Contractor

The equipment and facilities belonging to the Contractor and used for the Oil Operations shall be allocated to the Oil Costs account at a leasing rate intended to cover maintenance, repairs, amortization and the necessary services to the Oil Operations, on condition that such costs do not exceed those normally practiced in the Republic of Senegal for similar services.

3.4. Evaluation of transferred materials

All materials transferred from warehouses of the Contractor or its Affiliated Companies, or by any of the entities composing the Contractor or their Affiliated Companies, shall be evaluated as follows:

a) New materials

New materials (condition “A”) represent new materials which have never been used: one hundred percent (100%) of the Net Cost defined above in Article 3.2.

b) Materials in good condition

Materials in good condition (condition “B”) represent materials in good service condition still usable in their primary intended use without repair: seventy-five percent (75%) of the Net Cost of the new materials as defined in paragraph a).

c) Other used materials

Other used materials (condition “C”) represent materials still usable in their primary intended use, but only after repairs and overhaul: fifty percent (50%) of the Net Cost of the new materials defined in paragraph a).

d) Materials in poor condition

Materials in poor condition (condition “D”) represent materials which are no longer usable in their primary intended use but for other services: twenty- five percent (25%) of the Net Cost of the new materials defined in paragraph a).

e) Scrap and rejects

Scrap and rejects (condition “E”) represent materials beyond use and irreparable: current price for scrap.

f) Evaluation

The Parties may replace the rates mentioned in paragraphs b) through e) above with evaluations made jointly by their representatives.

3.5. Prices of materials and equipment transferred by the Contractor

a) Materials, equipment and consumable matter bought by all entities composing the Contractor or shared among them in kind, shall be evaluated according to the principles defined in Article 3.4 above.

b) Materials and equipment bought by any of the entities composing the Contractor or by Third Parties shall be evaluated on the basis of the sale price received, which under no circumstances shall be less than the price determined according to the principles defined in Article 3.4 above.

c) The corresponding amounts shall be credited to Oil Costs.

ARTICLE 4

AMORTIZATION OF FIXED ASSETS AND RESEARCH EXPENSES

4.1. Fixed Assets

For the purposes of recovery of the Oil Costs stipulated in Article 21.1 of the Contract and for the determination of the net taxable profit of the Contractor, the Oil Costs related to the fixed assets produced by the Contractor and necessary to the Oil Operations shall be amortized according to a straight-line amortization system.

The minimum period for amortization shall be five (5) Calendar Years (or ten (10) Calendar Years with respect to the production transportation fixed assets), starting from the Calendar Year during which the fixed assets are produced, or starting from the Calendar Year during which the said fixed assets are placed in normal service if this latter Calendar Year is later. The date of placement into normal service begins at the earliest year of regular production obtained starting from the fixed assets in question.

4.2. Research Expenses

The Oil Costs, with the exception of the Costs related to fixed assets, shall be recoverable and deductible starting in their year of implementation or according to the choice of the Contractor at an annual rate of amortization chosen by the latter and applicable according to the system of straight-line amortization.

In particular, for the purposes of the recovery of the Oil Costs provided in Article 21.1 of the Contract and for the determination of the net taxable profit of the Contractor, research expenses for Hydrocarbons incurred by the Contractor including in particular geological and geophysical expenses and the exploration drilling expenses (except for the productive exploration drilling expenses, which shall be capitalized) shall be considered as being recoverable and deductible

charges in their entirety starting in their year of implementation or may be amortized according to a system of amortization chosen by the Contractor.

ARTICLE 5

INVENTORIES

5.1. Frequency

The Contractor shall keep a permanent and cost inventory of all the goods used for the Oil Operations and shall conduct at reasonable intervals, at least once per year, physical inventories as required by the Parties.

5.2. Notification

A written notification of the intention of conducting a physical inventory shall be forwarded by the Contractor at least sixty (60) days before the beginning of the said inventory, so that the Minister and the entities composing the Contractor can be represented at their expense during this inventory.

5.3. Information

In the event that the Minister or an entity composing the Contractor is not represented during an inventory, such Party or Parties shall be linked by the inventory established by the Contractor which shall then supply such party or Parties with a copy of the said inventory.

ARTICLE 6

FINANCIAL AND ACCOUNTING STATEMENTS

The Contractor shall supply to the Ministry all reports, returns and statements provided by the provisions of the Contract and the regulations in effect and in particular the following financial and accounting statements:

6.1. Oil Cost Recovery Report

A quarterly report shall be submitted no later than one (1) month after the end of each Calendar Year quarter. It shall show the following elements of the Oil Costs accounts:

a) the amount of the Oil Costs remaining to be recovered at the beginning of the quarter;

b) the amount of the Oil Costs related to the quarter in question and recoverable according to the provisions of the Contract;

c) the quantity and the value of the production of Hydrocarbons paid out during the quarter by the Contractor with regard to the recovery of Oil Costs;

d) the amount of the earnings or products credited pursuant to Article 2.13 b) above during the quarter;

e) the amount of the Oil Costs remaining to be recovered at the end of the quarter.

In addition, an annual recovery report of Oil Costs shall be submitted before the end of the month of February of each Calendar Year.

7.2 Production Report

After the beginning of production, this monthly report shall be submitted no later than fifteen (15) days after the end of each month.

It shall show, for each month, the detail of the production of each Marketable Deposit and in particular the quantities of Hydrocarbons:

a) in stock at the beginning of the month;

b) removed during the month;

c) lost and used for the needs of the Oil Operations;

d) in stock at the end of the month.

Exhibit 10.2

THE REPUBLIC OF SENEGAL

One People — One Goal — One Faith

HYDROCARBON EXPLORATION AND PRODUCTION SHARING CONTRACT

SAINT LOUIS OFFSHORE PROFOND

Petro-Tim limited

Petrosen

TABLE OF CONTENTS

		Page

*CHAPTER ONE GENERAL PROVISIONS*		2

ARTICLE 1	DEFINITIONS	2
ARTICLE 2	PURPOSE AND TERM OF THE CONTRACT	5
ARTICLE 3	RIGHTS OF THE CONTRACTOR IN THE IMPLEMENTATION OF THE OIL OPERATIONS	5
ARTICLE 4	GENERAL OBLIGATIONS OF THE CONTRACTOR IN THE CONDUCT OF THE OIL OPERATIONS	6

*TITLE II RESEARCH*		8

ARTICLE 5	TERM OF THE RESEARCH PERIOD -RENEWALS	8
ARTICLE 6	SURFACE RETURNS AND RELEASE	9
ARTICLE 7	RESEARCH PROJECT OBLIGATIONS	10
ARTICLE 8	SURFACE AREA RENTS	13
ARTICLE 9	EVALUATION OF A DISCOVERY	13

*TITLE III EXPLOITATION*		16

ARTICLE 10	TERM OF THE EXPLOITATION PERIOD	16
ARTICLE 11	PRODUCTION PROGRAMMES	17
ARTICLE 12	NATURAL GAS	18
ARTICLE 13	HYDROCARBON MEASUREMENT	19
ARTICLE 14	HYDROCARBON TRANSPORT	19
ARTICLE 15	LOCAL DEMAND FOR CRUDE OIL	20

*TITLE IV JOINT PROVISIONS REGARDING RESEARCH AND EXPLOITATION*		20

ARTICLE 16	ANNUAL WORKS SCHEDULE	21
ARTICLE 17	INSPECTION OF OIL OPERATIONS	21
ARTICLE 18	INFORMATION AND REPORTS	22
ARTICLE 19	PERSONNEL, TRAINING AND EQUIPMENT	24
ARTICLE 20	ABANDONMENT AND TRANSFER OF ASSETS UPON EXPIRATION	25

*TITLE V ECONOMIC AND TAX PROVISIONS*		27

ARTICLE 21	PRICE OF RAW PETROLEUM AND NATURAL GAS	27
ARTICLE 22	RECOVERY OF OIL COSTS AND PRODUCTION SHARING	28
ARTICLE 23	TAXATION RULES	31
ARTICLE 24	SHARE EQUITY OF PETROSEN	32
ARTICLE 25	ACCOUNTING AND VERIFICATION	33
ARTICLE 26	IMPORTS AND EXPORTS	35
ARTICLE 27	FOREIGN EXCHANGE	36
ARTICLE 28	PAYMENTS	37

*TITLE VI MISCELLANEOUS PROVISIONS*		37

ARTICLE 29	CONTRACTOR’S RIGHTS OF TRANSFER AND INSPECTION	37
ARTICLE 30	TERMINATION OF THE CONTRACT	38
ARTICLE 31	FORCE MAJEURE	39
ARTICLE 32	ARBITRATION AND EXPERTISE	40
ARTICLE 33	APPLICABLE LAW -STABILIZATION OF CONDITIONS	41
ARTICLE 34	NOTIFICATIONS	41
ARTICLE 35	OTHER PROVISIONS	42

APPENDIX 1 - DELINEATION OF THE CONTRACT AREA		44

APPENDIX 2 - ACCOUNTING PROCEDURE		45

ARTICLE 1	GENERAL PROVISIONS	45
ARTICLE 2	PRINCIPLES AND BASES FOR ALLOCATION OF THE OIL PRODUCER COSTS	46
ARTICLE 3	PRINCIPLES GOVERNING THE ALLOCATION OF COSTS FROM THE PROVISION OF SERVICES, MATERIALS AND EQUIPMENT USED IN THE OIL OPERATIONS	50
ARTICLE 4	AMORTIZATION OF FIXED ASSETS AND RESEARCH EXPENSES	52
ARTICLE 5	INVENTORIES	53
ARTICLE 6	FINANCIAL AND ACCOUNTING STATEMENTS	53

CONTRACT

BETWEEN

party of the first part,

AND

Hereinafter collectively referred to as the “ Contractor ”,

party of the second part,

WHEREAS

The discovery and the operation of hydrocarbons are prominent economic policy objectives within the territory of the Republic of Senegal;

NOW THEREFORE, THE FOLLOWING HAS BEEN MUTUALLY AGREED AND ORDERED:

CHAPTER ONE

GENERAL PROVISIONS

ARTICLE 1

DEFINITIONS

The terms defined in this article shall have the following meaning for the entire Contract and the other texts that may supplement or modify the same:

1.1. “ Joint Operating Agreement ” means the Agreement executed between the Parties constituting the Contractor, in accordance with Article 4.9 below, setting forth the respective rights, interests and obligations of the said Parties concerning the Contractual Area and determining the terms under which the Oil Operations shall be carried out, and the expenses and results associated therewith shall be allocated among the said Parties.

1.2. “ Calendar Year ” means a period of twelve (12) consecutive months, beginning on January first (1st) and ending on the following December thirty- first (31st).

1.3. “ Contract Year ” means a period of twelve (12) consecutive months, beginning on the Effective Date or the anniversary of said Effective Date.

1.4. “ Budget ” means the detailed cost estimate of the Oil Operations forecast in the Annual Works Programme.

1.5. “ Contractor ” means, collectively, PETRO-TIM LIMITED and PETROSEN and any entity to which an interest might be transferred pursuant to Articles 24 and 29 below.

1.7. “ Oil Code ” means Law No. 98-05 dated 8 January 1998 establishing the legal and tax code for research, operation and the transport of hydrocarbons, and its implementing provisions.

1.8. “ Oil Costs ” means the entirety of the costs and expenses incurred by the Contractor within the framework of this Contract that are necessary according to industry rules in use in the international oil industry in performing the Oil Operations involving the Contract Area and determined according to the Accounting Procedure attached to this Contract as Appendix 2.

1.9. “ Effective Date ” means the effective date of the Contract, as defined in Article 35.5 below.

1.10. “ Dollar ” means the United States dollar.

1.11. “ State ” means the Republic of Senegal.

1.12. “ CFA Franc ” means a franc of the West African Monetary Union (UMOA).

1.13. “ Natural Gas ” means the dry and wet gas produced in isolation or together with the Crude Oil and any other gaseous component extracts from the wells.

1.14. “ Associated Natural Gas ” means the Natural Gas existing in a reservoir in a solution with Crude Oil or in the form of “gas-cap” in contact with the Crude Oil, and which is produced or may be produced in association with Crude Oil.

1.15. “ Non-Associated Natural Gas ” means Natural Gas excluding Associated Natural Gas.

1.16. “ Marketable Deposit ” means a geological entity filled with hydrocarbons, duly evaluated in accordance with the provisions in Article 9 below, and which, in accordance with the rules in use in the international oil industry, can be developed and produced under economic conditions for the Contractor.

1.17. “ Hydrocarbons ” means Crude Oil and Natural Gas.

1.18. “ Minister ” means at any time the Minister in charge of the sector of Oil Operations or his qualified representative.

1.19. “ Ministry ” means at any time the Ministry in charge of the sector of Oil Operations.

1.20. “ Oil Operations ” means all operations for the prospecting, research, evaluation, development, production, storage, transport and sale of the Hydrocarbons to the Delivery Point, including the treatment of Natural Gas, but excluding the refining and distribution of petroleum products.

1.21. “ Party (Parties) ” means the State and/or the Contractor.

1.22. “ Operation Perimeter ” means the portion of the Contract Area delineated by the perimeter of a Marketable Deposit established in accordance with the provisions of Article 10.1 below.

1.23. “ Crude Oil ” means: raw mineral oil, asphalt, ozokerite and any other liquid hydrocarbons at the natural state or obtained from Natural Gas by condensation or extraction, including condensates and Natural Gas liquids.

1.24. “ PETROSEN ” means Société des Pétroles du Sénégal and its successors and transferees.

1.25. “ Abandonment Plan ” means the plan for the demobilisation and abandonment of the facilities and infrastructures associated with the production of Hydrocarbons, in accordance with the provisions of Article 20.

1.26. “ Delivery Point ” means the F.O.B. point at the loading terminal of the Hydrocarbons in Senegal and/or any other point mutually agreed upon by the Parties.

1.27. “ Annual Works Schedule ” means the document describing the Oil Operations to be carried out in accordance with the provisions of Article 16 below.

1.28. “ Total Commercial Production ” means the total production of Crude Oil and Natural Gas obtained from the Exploitation Perimeter(s), less the quantities used for the purposes of the Oil Operations and any unavoidable losses.

1.29. “ Affiliated Company ” means any company that directly or indirectly controls or is controlled by a company referred to in Article 42 of the Oil Code or any company that directly or indirectly controls or is controlled by a company referred to in Article 42 of the Oil Code, it being understood that such control means the direct or indirect ownership by a company or any other entity of a percentage of stock or corporate shares of no less than 50%, that is sufficient to give rise to voting rights at the general stockholder meeting of another company or to give a determining power in the management of such other company.

1.30. “ State Company ” means a public establishment, a national company or a Senegalese company created in view of oil operations in which the State has a majority share equity.

1.31. “ Third Party ” means an entity other than an Affiliated Company.

1.32. “ Contract Area ” means the surface area defined in Appendix 1 of this Contract. The surface areas returned by the Contractor shall be considered as no longer comprising the Contract Area. On the other hand, the Operation Perimeter(s) shall form an integral part of the Contract Area during the time they are in effect.

ARTICLE 2

PURPOSE AND TERM OF THE CONTRACT

The Contractor shall act solely to carry out and perform the Oil Operations. It shall assign all technical, technological means, equipment and materials and all personnel necessary thereto.

The Contractor shall assume, at its own risk and expense, the entire responsibility for the implementation and the financing of the Oil Operations.

ARTICLE 3

RIGHTS OF THE CONTRACTOR
IN THE IMPLEMENTATION OF THE OIL OPERATIONS

3.1. In accordance with the provisions of applicable laws and regulations, in particular the Oil Code and the provisions of this Contract, the Contractor shall have the right:

b) to access any place located within the Contract Area, so as to perform therein the Oil Operations.

c) to implement any facilities and all work and in a general manner, all deeds and operations necessary for the conducting of the Oil Operations;

d) to use water necessary for the Oil Operations, provided that such use does not damage the water supply of the inhabitants and the water points for livestock;

e) to use the rocks, sand, clay, gypsum, lime and other similar substances, necessary to the conducting of the Oil Operations.

ARTICLE 4

GENERAL OBLIGATIONS OF THE CONTRACTOR
IN THE CONDUCT OF THE OIL OPERATIONS