Edgar Filing: Kosmos Energy Ltd.

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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 March 31, 2013

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

For the transition period from to

Commission file number: 001-35167

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)

Bermuda		98-0686001
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

Clarendon House
2 Church Street
Hamilton, Bermuda		HM 11
(Address of principal executive offices)		(Zip Code)

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

Not applicable

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x Noo

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 May 2, 2013
Common Shares, $0.01 par value		388,584,981

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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 2.

	Page
PART I. FINANCIAL INFORMATION

Glossary and Select Abbreviations	2

Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	5
Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	6
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2013 and 2012	7
Consolidated Statements of Shareholders’ Equity for the three months ended March 31, 2013	8
Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	9
Notes to Consolidated Financial Statements	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3. Quantitative and Qualitative Disclosures about Market Risk	30
Item 4. Controls and Procedures	31

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	33
Item 1A. Risk Factors	33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3. Defaults Upon Senior Securities	33
Item 4. Mine Safety Disclosures	33
Item 5. Other Information	33
Item 6. Exhibits	38
Signatures	39
Index to Exhibits	40

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

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

“2D seismic data”		Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.
“3D seismic data”		Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
“API”		A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
“ASC”		Financial Accounting Standards Board Accounting Standards Codification.
“ASU”		Financial Accounting Standards Board Accounting Standards Update.
“Barrel” or “Bbl”		A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
“BBbl”		Billion barrels of oil.
“BBoe”		Billion barrels of oil equivalent.
“Bcf”		Billion cubic feet.
“Boe”		Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
“Boepd”		Barrels of oil equivalent per day.
“Bopd”		Barrels of oil per day.
“Bwpd”		Barrels of water per day.
“Debt cover ratio”		The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.
“Developed acreage”		The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development”		The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
“Dry hole”		A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“EBITDAX”		Net income (loss) plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) equity-based compensation expense, (4) (gain) loss on commodity derivatives, (5) (gain) loss on sale of oil and gas properties, (6) interest (income) expense, (7) income taxes, (8) loss on extinguishment of debt, (9) doubtful accounts expense, and (10) similar items.
“E&P”		Exploration and production.
“FASB”		Financial Accounting Standards Board.
“Farm-in”		An agreement whereby an oil company acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.
“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.
“Ghana Obligors”		Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Finance International, Kosmos Energy Development, Kosmos Energy Ghana HC and an “Obligor” from time to time, as defined under the Facility Agreement, as amended and restated, dated November 23, 2012.

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“Interest cover ratio”		The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
“Loan life cover ratio”		The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the final maturity date of the Facility plus the net present value of capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility.
“MBbl”		Thousand barrels of oil.
“Mcf”		Thousand cubic feet of natural gas.
“Mcfpd”		Thousand cubic feet per day of natural gas.
“MMBbl”		Million barrels of oil.
“MMBoe”		Million barrels of oil equivalent.
“MMcf”		Million cubic feet of natural gas.
“Natural gas liquid” or “NGL”		Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
“Petroleum contract”		A contract in which the owner of minerals gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce minerals 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.
“Prospect(s)”		A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.
“Proved reserves”		Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
“Proved developed reserves”		Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“Proved undeveloped reserves”		Proved undeveloped reserves are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“Reconnaissance contract”		A contract in which the owner of minerals gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but does not convey an exclusive option to explore for, develop, and/or produce minerals from the lease area.
“Shelf margin”		The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
“Structural trap”		A structural strap 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.

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“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.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	March 31,			December 31,
	2013			2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	497,289		$	515,164
Restricted cash	20,455			21,341
Receivables:
Joint interest billings	27,747			21,539
Oil sales	106,707			108,995
Other	2,813			3,682
Inventories	30,120			33,281
Prepaid expenses and other	10,768			10,470
Current deferred tax assets	27,806			34,585
Derivatives	3,204			1,061
Total current assets	726,909			750,118

Property and equipment:
Oil and gas properties, net	1,527,267			1,510,312
Other property, net	15,046			15,450
Property and equipment, net	1,542,313			1,525,762

Other assets:
Restricted cash	29,884			29,884
Deferred financing costs, net of accumulated amortization of $16,619 and $13,922, respectively	47,484			50,214
Long-term deferred tax assets	12,088			10,145
Total assets	$	2,358,678		$	2,366,123

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	48,785		$	128,855
Accrued liabilities	58,340			41,021
Derivatives	18,004			20,377
Total current liabilities	125,129			190,253

Long-term liabilities:
Long-term debt	1,000,000			1,000,000
Derivatives	3,785			3,226
Asset retirement obligations	29,957			27,484
Deferred tax liability	113,585			104,137
Other long-term liabilities	18,725			12,117
Total long-term liabilities	1,166,052			1,146,964

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at March 31, 2013 and December 31, 2012	—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 391,447,003 and 391,423,703 issued at March 31, 2013 and December 31, 2012, respectively	3,914			3,914
Additional paid-in capital	1,731,819			1,712,880
Accumulated deficit	(663,082		)	(683,176		)
Accumulated other comprehensive income	3,326			3,685
Treasury stock, at cost, 2,860,229 and 2,731,941 shares at March 31, 2013 and December 31, 2012, respectively	(8,480		)	(8,397		)
Total shareholders’ equity	1,067,497			1,028,906
Total liabilities and shareholders’ equity	$	2,358,678		$	2,366,123

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	Three Months Ended March 31,
	2013		2012
Revenues and other income:
Oil and gas revenue	$	228,066	$	115,771
Interest income	70		746
Other income	254		30

Total revenues and other income	228,390		116,547

Costs and expenses:
Oil and gas production	24,401		7,326
Exploration expenses	23,296		39,644
General and administrative	40,030		39,323
Depletion and depreciation	58,649		31,649
Amortization—deferred financing costs	2,698		2,194
Interest expense	8,991		13,058
Derivatives, net	5,508		3,860
Other expenses, net	632		748

Total costs and expenses	164,205		137,802

Income (loss) before income taxes	64,185		(21,255		)
Income tax expense	44,091		16,286

Net income (loss)	$	20,094	$	(37,541	)

Net income (loss) per share:
Basic	$	0.05	$	(0.10	)
Diluted	$	0.05	$	(0.10	)

Weighted average number of shares used to compute net income (loss) per share:
Basic	375,284		369,227
Diluted	375,651		369,227

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Net income (loss)	$	20,094		$	(37,541	)
Other comprehensive income (loss):
Reclassification adjustments for derivative (gains) losses included in net income (loss)	(359		)	214
Other comprehensive income (loss)	(359		)	214
Comprehensive income (loss)	$	19,735		$	(37,327	)

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

(Unaudited)

	Common Shares			Additional Paid-in		Accumulated			Accumulated Other Comprehensive			Treasury
	Shares	Amount		Capital		Deficit			Income			Stock			Total
Balance as of December 31, 2012	391,424	$	3,914	$	1,712,880	$	(683,176	)	$	3,685		$	(8,397	)	$	1,028,906
Equity-based compensation	—	—		18,938		—			—			—			18,938
Derivatives, net	—	—		—		—			(359		)	—			(359		)
Restricted stock awards	23	—		—		—			—			—			—
Restricted stock forfeitures	—	—		1		—			—			(1		)	—
Purchase of treasury stock	—	—		—		—			—			(82		)	(82		)
Net income	—	—		—		20,094			—			—			20,094
Balance as of March 31, 2013	391,447	$	3,914	$	1,731,819	$	(663,082	)	$	3,326		$	(8,480	)	$	1,067,497

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Operating activities
Net income (loss)	$	20,094		$	(37,541	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	61,347			33,843
Deferred income taxes	20,915			7,713
Unsuccessful well costs	9,753			8,270
Change in fair value of derivatives	534			2,045
Cash settlements on derivatives	(4,850		)	(2,422		)
Equity-based compensation	18,938			21,290
Other	1,396			3,097
Changes in assets and liabilities:
(Increase) decrease in receivables	(2,382		)	182,519
(Increase) decrease in inventories	3,637			(5,703		)
Increase in prepaid expenses and other	(298		)	(213		)
Decrease in accounts payable	(80,070		)	(72,185		)
Increase in accrued liabilities	17,855			4,190
Net cash provided by operating activities	66,869			144,903

Investing activities
Oil and gas assets	(83,491		)	(68,070		)
Other property	(814		)	(3,110		)
Restricted cash	886			72
Net cash used in investing activities	(83,419		)	(71,108		)

Financing activities
Purchase of treasury stock	(82		)	—
Deferred financing costs	(1,243		)	(1,599		)
Net cash used in financing activities	(1,325		)	(1,599		)

Net increase (decrease) in cash and cash equivalents	(17,875		)	72,196
Cash and cash equivalents at beginning of period	515,164			673,092
Cash and cash equivalents at end of period	$	497,289		$	745,288

Supplemental cash flow information
Cash paid for:
Interest	$	6,585		$	10,177
Income taxes	$	4,300		$	5,013

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

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

We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our asset portfolio includes existing production and other major project developments offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco and Suriname and onshore Cameroon. 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 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 March 31, 2013, the consolidated results of operations for the three months ended March 31, 2013 and 2012, and consolidated cash flows for the three months ended March 31, 2013 and 2012. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2012, included in our annual report on Form 10-K.

Reclassifications

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

Inventories

Inventories consisted of $29.2 million and $33.1 million of materials and supplies and $0.9 million and $0.2 million of hydrocarbons as of March 31, 2013 and December 31, 2012, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or market.

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

Variable Interest Entity

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

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Kosmos Energy Finance International’s following assets and liabilities are shown separately on the face of the consolidated balance sheet as of March 31, 2013 and December 31, 2012: current restricted cash; long-term debt; and current and long-term derivatives liabilities. At March 31, 2013, Kosmos Energy Finance International had $107.2 million in cash and cash equivalents; $0.3 million in prepaid expenses and other; $40.2 million deferred financing costs, net; $0.3 million in accrued liabilities and $6.7 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet. At December 31, 2012, Kosmos Energy Finance International had $118.8 million in cash and cash equivalents; $0.2 million in prepaid expenses and other; $42.2 million deferred financing costs, net; $0.5 million in accrued liabilities and $6.6 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet.

3. Property and Equipment

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

	March 31,			December 31,
	2013			2012
	(In thousands)
Oil and gas properties:
Proved properties	$	702,352		$	682,276
Unproved properties	501,699			454,391
Support equipment and facilities	696,569			687,835
Total oil and gas properties	1,900,620			1,824,502
Less: accumulated depletion	(373,353		)	(314,190		)
Oil and gas properties, net	1,527,267			1,510,312

Other property	28,143			27,316
Less: accumulated depreciation	(13,097		)	(11,866		)
Other property, net	15,046			15,450

Property and equipment, net	$	1,542,313		$	1,525,762

We recorded depletion expense of $56.6 million and $30.1 million for the three months ended March 31, 2013 and 2012, respectively. The Company had depletion costs of $2.5 million and nil included in crude oil inventory and other receivables as of March 31, 2013 and December 31, 2012, respectively.

4. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the three months ended March 31, 2013. The table excludes $8.1 million in costs that were capitalized and subsequently expensed during the same period.

	Three months ended March 31, 2013
	(In thousands)
Beginning balance	$	372,492
Additions to capitalized exploratory well costs pending the determination of proved reserves	937
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	(1,705		)
Ending balance	$	371,724

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The following table provides 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:

	March 31, 2013		December 31, 2012
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	56,903	$	106,635
Exploratory well costs capitalized for a period one to two years	215,320		179,933
Exploratory well costs capitalized for a period three to four years	99,501		85,924
Ending balance	$	371,724	$	372,492
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	7		7

As of March 31, 2013, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to Mahogany, Teak-1, Teak-2 and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Tweneboa, Enyenra and Ntomme discoveries in the Deepwater Tano (“DT”) Block, which are all in Ghana.

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

Teak-1 Discovery—Two appraisal wells have been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-1 discovery is expected to be made by the WCTP Block partners in 2014. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

Teak-2 Discovery—We have performed a gauge installation on the well and are reprocessing seismic data. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-2 discovery is expected to be made by the WCTP Block partners in 2014. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

Akasa Discovery—We have performed a drill stem test and gauge installation on the well and are analyzing the data. Following additional appraisal and evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in 2013. 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—During 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries and are awaiting approval from the government of Ghana.

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5. Accounts Payable and Accrued Liabilities

At March 31, 2013 and December 31, 2012, $48.8 million and $128.9 million, respectively, were recorded for invoices received but not paid. Accrued liabilities were $58.3 million and $41.0 million at March 31, 2013 and December 31, 2012, respectively, and consisted of the following:

		March 31,		December 31,
		2013		2012
	(In thousands)
Accrued liabilities:
Accrued exploration, development and production		$	16,004	$	20,616
Accrued general and administrative expenses		5,912		5,089
Accrued taxes other than income		12,986		11,124
Accrued interest		370		—
Income taxes		23,068		4,192
		$	58,340	$	41,021

6. Debt

Facility

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

The Facility provides a revolving-credit and letter of credit facility for an availability period that expires on May 15, 2014, (in the case of the revolving-credit facility) and on the final maturity date (in the case of the letter of credit facility). The available facility amount is subject to borrowing base constraints and is also constrained by an amortization schedule (once repayments under the Facility begin). The Facility was amended in April 2013 to change the expiration of the availability period from May 15, 2014 to December 15, 2014 and to revise the amortization schedule. Beginning on December 15, 2014, outstanding borrowings will be subject to an amortization schedule. The final maturity date of March 29, 2018 was not changed by the amendment.

In March 2013, as part of the normal borrowing base determination process, the availability under the Facility was reduced $41.3 million to $1.3 billion. As of March 31, 2013, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the Facility was $299.1 million.

Corporate Revolver

In November 2012, we secured a revolving credit facility (the “Corporate Revolver”) from a number of financial institutions. As of March 31, 2013 and December 31, 2012, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $260.0 million. 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.

At March 31, 2013, the scheduled maturities of debt during the five year period and thereafter are as follows:

	Payments Due by Year
	2013(1)		2014		2015		2016		2017		Thereafter
	(In thousands)
Facility(2)	$	—	$	134,759	$	325,235	$	35,272	$	393,623	$	111,111

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

(2) The scheduled maturities of debt are based on the level of borrowings and the forecasted available borrowing base as of March 31, 2013. Any increases or decreases in the level of borrowings or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

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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 March 31, 2013.

			Weighted Average Dated Brent Price per Bbl
Term	Type of Contract	MBbl	Deferred Premium		Floor		Ceiling		Calls
2013:
April - December	Three-way collars	1,125	$	4.82	$	95.00	$	105.00	$	125.00
April - December	Three-way collars	756	—		87.50		115.00		135.00
April - December	Three-way collars	750	—		90.00		115.39		135.00
April - December	Three-way collars	750	—		90.08		115.00		135.00
2014:
January - December	Three-way collars	1,500	1.22		85.00		115.00		140.00
January - December	Three-way collars	1,000	—		85.00		115.01		140.00

Provisional Oil Sales

At March 31, 2013, we had sales volumes of 995.1 MBbl priced at an average of $110.45 per Bbl, after differentials, which are subject to final pricing over the next month.

Interest Rate Swaps Derivative Contracts

The following table summarizes our open interest rate swaps as of March 31, 2013, whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate:

Term	Weighted Average Notional Amount		Weighted Average Fixed Rate		Floating Rate
	(In thousands)
April 2013 — December 2013	$	227,103	2.06	%	6-month LIBOR
January 2014 — December 2014	133,434		1.99	%	6-month LIBOR
January 2015 — December 2015	45,319		2.03	%	6-month LIBOR
January 2016 — June 2016	12,500		2.27	%	6-month LIBOR

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The following tables disclose the Company’s derivative instruments as of March 31, 2013 and December 31, 2012 and gain/(loss) from derivatives during the three months ended March 31, 2013 and 2012, respectively:

		Estimated Fair Value Asset (Liability)
		March 31,			December 31,
Type of Contract	Balance Sheet Location	2013			2012
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative asset:
Commodity(1)	Derivatives assets—current	$	3,204		$	1,061

Derivative liability:
Commodity(2)	Derivatives liabilities—current	(14,060		)	(17,005		)
Interest rate	Derivatives liabilities—current	(3,944		)	(3,372		)
Commodity(3)	Derivatives liabilities—long-term	(1,817		)	(659		)
Interest rate	Derivatives liabilities—long-term	(1,968		)	(2,567		)
Total derivatives not designated as hedging instruments		$	(18,585	)	$	(22,542	)

(1) The commodity derivative asset represents our provisional oil sales contract.

(2) Includes $1.0 million and $3.4 million, as of March 31, 2013 and December 31, 2012, respectively of cash settlements made on our commodity derivative contracts which were settled in the month subsequent to period end. Also, includes deferred premiums of $6.3 million and $7.6 million related to commodity derivative contracts as of March 31, 2013 and December 31, 2012, respectively.

(3) Includes deferred premiums of $1.5 million and $2.4 million related to commodity derivative contracts as of March 31, 2013 and December 31, 2012, respectively.

		Amount of Gain/(Loss)
		Three Months Ended March 31,
Type of Contract	Location of Gain/(Loss)	2013			2012
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	359		$	(214	)
Total derivatives in cash flow hedging relationships		$	359		$	(214	)
Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	4,588		$	2,740
Commodity	Derivatives, net	(5,508		)	(3,860		)
Interest rate	Interest expense	27			(710		)
Total derivatives not designated as hedging instruments		$	(893	)	$	(1,830	)

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

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

In accordance with the mark-to-market method of accounting, the Company recognizes changes in fair values of its derivative contracts as gains or losses in earnings during the period in which they occur. The fair value of the effective portion of the interest rate derivative contracts on May 31, 2010, is reflected in AOCI and is being transferred to interest expense over the remaining term of the contracts. The Company expects to reclassify $1.6 million of gains from AOCI to interest expense within the next 12 months. See Note 8—Fair Value Measurements for additional information regarding the Company’s derivative instruments.

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Offsetting of Derivative Assets and Derivative Liabilities

The tables below provide additional information related to derivative instruments on our consolidated balance sheets which have the right of set off only when there is a defaulting party subject to master netting arrangements with our counterparties:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet		Net Amounts of Liabilities Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet			Net Amount
	(In thousands)
March 31, 2013
Commodity derivatives	$	15,877	$	—	$	15,877	$	(15,877	)	$	—
Interest rate derivatives	5,912		—		5,912		(5,912		)	—
Total	$	21,789	$	—	$	21,789	$	(21,789	)	$	—

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet		Net Amounts of Liabilities Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet			Net Amount
	(In thousands)
December 31, 2012
Commodity derivatives	$	17,664	$	—	$	17,664	$	(17,664	)	$	—
Interest rate derivatives	5,939		—		5,939		(5,939		)	—
Total	$	23,603	$	—	$	23,603	$	(23,603	)	$	—

8. Fair Value Measurements

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

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

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

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

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2013 and December 31, 2012, for each fair value hierarchy level:

	Fair Value Measurements Using:
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
March 31, 2013
Assets:
Commodity derivatives	$	—	$	3,204		$	—	$	3,204
Liabilities:
Commodity derivatives	—		(15,877		)	—		(15,877		)
Interest rate derivatives	—		(5,912		)	—		(5,912		)
Total	$	—	$	(18,585	)	$	—	$	(18,585	)

December 31, 2012
Assets:
Commodity derivatives	$	—	$	1,061		$	—	$	1,061
Liabilities:
Commodity derivatives	—		(17,664		)	—		(17,664		)
Interest rate derivatives	—		(5,939		)	—		(5,939		)
Total	$	—	$	(22,542	)	$	—	$	(22,542	)

All fair values have been adjusted for nonperformance risk resulting in a decrease of the commodity derivative liabilities of approximately $0.3 million and a decrease of the interest rate derivatives of approximately of $0.2 million as of March 31, 2013.

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The carrying values of our debt approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods. Our long-term receivables, if any, after any allowances for doubtful accounts approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

Commodity Derivatives

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

Provisional Oil Sales

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

Interest Rate Derivatives

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

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9. Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations:

	March 31,
	2013
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	27,484
Liabilities incurred during period	1,676
Revisions in estimated retirement obligations	—
Liabilities settled during period	—
Accretion expense	797
Ending asset retirement obligations	$	29,957

10. Equity-based Compensation

Restricted Stock Awards and Restricted Stock Units

We record compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $18.9 million and $21.3 million during the three months ended March 31, 2013 and 2012, respectively. The total tax benefit for the three months ended March 31, 2013 and 2012 was $6.4 million and $7.3 million, respectively.

The following table reflects the outstanding restricted stock awards as of March 31, 2013:

			Weighted-		Market / Service	Weighted-
	Service Vesting Restricted Stock		Average Grant-Date		Vesting Restricted Stock	Average Grant-Date
	Awards		Fair Value		Awards	Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2012	9,898		$	16.92	3,534	$	12.93
Granted	23		12.35		—	—
Forfeited	(121	)	15.37		—	—
Vested	(57	)	13.16		—	—
Outstanding at March 31, 2013	9,743		16.95		3,534	12.93

The following table reflects the outstanding restricted stock units as of March 31, 2013:

			Weighted-		Market / Service		Weighted-
	Service Vesting Restricted Stock		Average Grant-Date		Vesting Restricted Stock		Average Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2012	1,023		$	10.59	825		$	15.81
Granted	178		12.09		98		15.81
Forfeited	(16	)	10.98		(5	)	15.81
Vested	—		—		—		—
Outstanding at March 31, 2013	1,185		10.81		918		15.81

As of March 31, 2013, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $156.9 million over a weighted average period of 2.33 years. At March 31, 2013, the Company had approximately 7.5 million shares that remain available for issuance under the LTIP.

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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 was $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 was 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 was 0.5%.

11. Income Taxes

The income tax expense was $44.1 million and $16.3 million for the three months ended March 31, 2013 and 2012, respectively. The income tax provision consists of U.S. and Ghanaian income and Texas margin taxes.

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

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Bermuda	$	(6,777	)	$	(3,168	)
United States	2,370			3,312
Foreign—other	68,592			(21,399		)
Income (loss) before income taxes	$	64,185		$	(21,255	)

Our effective tax rate for the three months ended March 31, 2013 and 2012 was 69% and (77)%, respectively. The effective tax rate for the United States is approximately 37% and 38% for the three months ended March 31, 2013 and 2012, respectively. The effective tax rate for Ghana is approximately 37% and 34% for the three months ended March 31, 2013 and 2012, respectively. The effective tax rate for our other foreign jurisdictions is 0%. Our other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate, or we have experienced losses in those countries and have a full valuation allowance reserved against the corresponding net deferred tax assets.

The Company has no material unrecognized income tax benefits.

A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2009 through 2012 and to Texas margin tax examinations for the tax years 2008 through 2012. In addition, the Company is open to income tax examinations for years 2004 through 2012 in Ghana.

As of March 31, 2013, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense, but has had no need to accrue any to date.

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12. Net Income (Loss) Per Share

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

	Three Months Ended March 31,
	2013		2012
	(In thousands, except per share data)
Numerator:
Net income (loss)	$	20,094	$	(37,541	)
Less: Basic income allocable to participating securities(1)	512		—
Basic net income (loss) allocable to common shareholders	19,582		(37,541		)
Diluted adjustments to income allocable to participating securities(1)	2		—
Diluted net income (loss) allocable to common shareholders	$	19,584	$	(37,541	)
Denominator:
Weighted average number of shares used to compute net income (loss) per share:
Basic	375,284		369,227
Restricted stock awards and units(1)(2)	367		—
Diluted	375,651		369,227
Net income (loss) per share:
Basic	$	0.05	$	(0.10	)
Diluted	$	0.05	$	(0.10	)

(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 (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position.

(2) For the three months ended March 31, 2013 and 2012, we excluded 13.8 million and 21.0 million outstanding restricted stock awards and units, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

13. Commitments and Contingencies

We are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s consolidated financial statements.

14. Subsequent Event

In April 2013, the Company entered into a farm-in agreement with Antrim Energy Inc., whereby Kosmos is acquiring a 75% participating interest and operatorship, covering Licensing Option 11/5 offshore the west coast of Ireland. As part of the agreement, Kosmos will reimburse a portion of previously-incurred exploration costs, as well as carry the partner on future 3D seismic costs.

In April 2013, the Company entered into a farm-in agreement with Europa Oil & Gas (Holdings) plc, whereby Kosmos is acquiring an 85% participating interest and operatorship, covering Licensing Option 11/7 and 11/8 offshore the west coast of Ireland. As part of the agreement, Kosmos will reimburse a portion of previously-incurred exploration costs, as well as carry the partner on future 3D seismic costs. Contingent upon an election by Kosmos and our partner to enter into a subsequent exploration drilling phase on one or both of the blocks, Kosmos will also fund 100% of the costs of the first exploration well on each block, subject to an investment cap of $90.0 million and $110.0 million, respectively, on each block.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2012, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

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

Recent Developments

Debt

In April 2013, the availability under the Corporate Revolver was increased from $260.0 million to $300.0 million by additional commitments from existing and new financial institutions.

Ghana

During the first quarter of 2013, we had two liftings of oil totaling 1,991 MBbl from the Jubilee Field production resulting in revenues of $228.1 million. Our average realized price was $114.54 per barrel.

We previously received an approval for the Phase 1A PoD of the Jubilee Field, and production from Phase 1A commenced in late 2012. The Phase 1A program includes the drilling of up to eight additional wells consisting of up to five production wells and three water injection wells. Program execution is underway and expected to continue into the first half of 2014.

During the first quarter, we successfully drilled the Enyenra-6A appraisal well on the DT Block, nearly 3 kilometers south of Enyenra-4. Results of the well are being integrated into our development plans.

The Sapele-1 exploration well on the DT Block was spud in December 2012. Drilling of the well was completed in February 2013. The well was not considered a productive well and accordingly was plugged and abandoned.

In January 2013, we relinquished the discovery area associated with the Banda discovery on the WCTP Block, as we do not consider this discovery to be commercially viable. As the exploration phase of the WCTP PA has expired, we no longer have any rights to this discovery area (unless we enter into a new petroleum agreement with the Ghana Ministry of Energy and the Ghana National

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Petroleum Company covering this and other relinquished areas of the WCTP Block). This relinquishment did not have a material impact on our consolidated financial statements for the quarter ended March 31, 2013, as we previously recorded the unsuccessful well costs associated with the Banda-1 exploration well as exploration expenses in 2011.

Cameroon

The Sipo-1 exploration well on the Ndian River Block was spud in February 2013 and well results are expected by the end of May 2013. As of March 31, 2013, we have capitalized approximately $47.6 million of exploratory well costs related to the Sipo-1 exploration well.

Ireland

Mauritania

During the first quarter of 2013, we commenced a 2D seismic data acquisition program on approximately 6,000 line-kilometers, covering Blocks C8, C12 and C13 offshore Mauritania. A 3D seismic program over portions of the blocks will be targeted for commencement in mid-2013.

Morocco

In January 2013, Kosmos closed an agreement to acquire an additional 37.5% participating interest in the Essaouira Offshore Block from Canamens Energy Morocco SARL, one of our block partners. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the Essaouira Offshore Block will be 75%.

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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 months ended, March 31, 2013 and 2012, are included in the following table:

	Three Months Ended March 31,
	2013		2012
	(In thousands, except per barrel data)
Sales volumes:
MBbl	1,991		931

Revenues:
Oil sales	$	228,066	$	115,771
Average sales price per Bbl	114.54		124.30

Costs:
Oil production, excluding workovers	$	13,419	$	7,326
Oil production, workovers	10,982		—
Total oil production costs	24,401		7,326

Depletion	56,621		30,055

Average cost per Bbl:
Oil production, excluding workovers	$	6.73	$	7.87
Oil production, workovers	5.52		—
Total oil production costs	12.25		7.87

Depletion	28.44		32.27
Oil production cost and depletion costs	$	40.69	$	40.14

The following table shows the number of wells in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of March 31, 2013:

					Wells Suspended or
	Actively Drilling or Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
West Cape Three Points	—	—	—	—	8	2.47	—	—
Deepwater Tano	—	—	—	—	12	2.16	—	—
Jubilee Unit	—	—	—	—	—	—	3	0.72
Cameroon
Ndian River	1	1.00	—	—	—	—	—	—
Total	1	1.00	—	—	20	4.63	3	0.72

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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 March 31, 2013 compared to three months ended March 31, 2012

	Three Months Ended March 31,					Increase
	2013		2012			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	228,066	$	115,771		$	112,295
Interest income	70		746			(676		)
Other income	254		30			224
Total revenues and other income	228,390		116,547			111,843
Costs and expenses:
Oil and gas production	24,401		7,326			17,075
Exploration expenses	23,296		39,644			(16,348		)
General and administrative	40,030		39,323			707
Depletion and depreciation	58,649		31,649			27,000
Amortization—deferred financing costs	2,698		2,194			504
Interest expense	8,991		13,058			(4,067		)
Derivatives, net	5,508		3,860			1,648
Other expenses, net	632		748			(116		)
Total costs and expenses	164,205		137,802			26,403
Income (loss) before income taxes	64,185		(21,255		)	85,440
Income tax expense	44,091		16,286			27,805
Net income (loss)	$	20,094	$	(37,541	)	$	57,635

Oil and gas revenue. Oil and gas revenue increased by $112.3 million during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012. The increase is primarily due to having two liftings of oil during the three months ended March 31, 2013 as compared to having one lifting of oil during the three months ended March 31, 2012. This increase is partially offset by a lower realized price per barrel during the three months ended March 31, 2013.

Oil and gas production. Oil and gas production costs increased by $17.1 million during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012. The increase is primarily due to $11.0 million of workover and rig equipment maintenance costs during the three months ended March 31, 2013, for which we did not incur during the three months ended March 31, 2012. Additionally, we had two liftings of oil and an increase in routine operating expenses during the three months ended March 31, 2013 as compared to one lifting of oil during the three months ended March 31, 2012. Our average production cost per barrel was $12.25 and $7.87 for the three months ended March 31, 2013 and 2012, respectively.

Exploration expenses. Exploration expenses decreased by $16.3 million during the three months ended March 31, 2013, as compared to the three months ended March 31, 2012. During the three months ended March 31, 2013, we incurred $10.6 million for seismic costs for Morocco, Mauritania and new business and $9.8 million of unsuccessful well costs, primarily related to the Ghana Sapele-1 exploration well. During the three months ended March 31, 2012, we incurred $28.9 million for seismic costs for Morocco, Ghana and Cameroon and $8.3 million of unsuccessful well costs, primarily related to the Ghana Teak-4A appraisal well.

General and administrative. General and administrative costs increased by $0.7 million during the three months ended March 31, 2013, as compared to the three months ended March 31, 2012. Total non-cash general and administrative costs were $18.9 million and $21.3 million for the three months ended March 31, 2013 and 2012, respectively.

Depletion and depreciation. Depletion and depreciation increased $27.0 million during the three months ended March 31, 2013, as compared with the three months ended March 31, 2012. The increase is primarily due to the sale of two liftings of oil during the three months ended March 31, 2013 as compared to one lifting of oil during the three months ended March 31, 2012.

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Interest expense. Interest expense decreased by $4.1 million during the three months ended March 31, 2013, as compared to the three months ended March 31, 2012, primarily due to a decrease in the outstanding debt balance and a decrease in the unrealized loss on our interest rate derivative instruments related to changes in fair value.

Derivatives, net. Derivatives, net increased $1.6 million during the three months ended March 31, 2013, as compared with March 31, 2012, due to the change in fair value and notional amounts outstanding of our commodity derivative instruments.

Income tax expense. The Company’s effective tax rates for the three months ended March 31, 2013 and 2012 were 69% and (77%), respectively. The large effective tax rates for both periods presented are due to losses incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits and losses 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 $27.8 million during the three months ended March 31, 2013, as compared with March 31, 2012, 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 secured funding from issuances of equity and commercial debt facilities to meet our ongoing liquidity requirements. We received our first oil sales in January 2011 from Jubilee Field production, which generated cash flows from operations from 2011 to present. Accordingly, the cash flows generated from our operating activities may also provide an additional source of future funding.

Significant Sources of Capital

Facility

Corporate Revolver

In November 2012, we secured the Corporate Revolver from a number of financial institutions. As of March 31, 2013 and December 31, 2012, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $260.0 million. In April 2013, the availability under the Corporate Revolver was increased from $260.0 million to $300.0 million by additional commitments from existing and new financial institutions.

The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking and

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financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.

Capital Expenditures and Investments

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

· complete our 2013 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.

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 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.

2013 Capital Program

Our estimate for the 2013 capital program remains at $525.0 million. The 2013 capital expenditure budget consists of:

· approximately 55% for developmental related expenditures offshore Ghana; and

· approximately 45% 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 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.

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The following table presents our liquidity and financial position as of March 31, 2013:

	March 31, 2013
	(In thousands)
Cash and cash equivalents	$	497,289
Drawings under the Facility	1,000,000
Net debt	502,711

Availability under the Facility	$	299,141
Availability under the Corporate Revolver(1)	260,000
Available borrowings plus cash and cash equivalents	1,056,430

(1) 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.

Cash Flows

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net cash provided by (used in):
Operating activities	$	66,869		$	144,903
Investing activities	(83,419		)	(71,108		)
Financing activities	(1,325		)	(1,599		)

Operating activities. Net cash provided by operating activities for the three months ended March 31, 2013 was $66.9 million compared with net cash provided by operating activities for the three months ended March 31, 2012 of $144.9 million. The decrease in cash provided by operating activities in the three months ended March 31, 2013 when compared to the same period in 2012 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 three months ended March 31, 2013 was 83.4 million compared with net cash used in investing activities for the three months ended March 31, 2012 of $71.1 million. The increase in cash used in investing activities in the three months ended March 31, 2013 when compared to the same period in 2012 was primarily attributable to changes in expenditures for oil and gas assets primarily in Cameroon.

Financing activities. Net cash used in financing activities for the three months ended March 31, 2013 was $1.3 million compared with net cash used in financing activities for the three months ended March 31, 2012 of $1.6 million.

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Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2013:

	Payments Due By Year(3)
	Total		2013(4)		2014		2015		2016		2017		Thereafter
	(In thousands)
Facility(1)	$	1,000,000	$	—	$	134,759	$	325,235	$	35,272	$	393,623	$	111,111
Interest payments on long-term debt(2)	171,457		35,610		47,493		36,888		28,749		21,181		1,536
Operating leases	20,859		2,118		2,921		3,022		3,122		3,223		6,453

(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 forecasted available borrowing base as of March 31, 2013. 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 March 31, 2013, 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.

(3) 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 and farm-in agreements.

(4) Represents payments for the period from April 1, 2013 through December 31, 2013.

The following table presents maturities by expected maturity dates under the Facility, 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.

	April 1 Through December 31,			Years Ending December 31,															Liability Fair Value at March 31,
	2013			2014			2015			2016			2017			Thereafter			2013 (5)
	(In thousands, except percentages)
Variable rate debt:
Facility(1)	$	—		$	134,759		$	325,235		$	35,272		$	393,623		$	111,111		$	(1,000,000	)
Weighted average interest rate (2)	3.56		%	4.02		%	4.36		%	5.41		%	6.28		%	6.73		%
Interest rate swaps:
Notional debt amount(3)	$	75,208		$	47,033		$	16,875		$	6,250		$	—		$	—		$	(1,631	)
Fixed rate payable	2.22		%	2.22		%	2.22		%	2.22		%
Variable rate receivable(4)	0.49		%	0.59		%	0.77		%	1.08		%
Notional debt amount(3)	$	75,208		$	47,033		$	16,875		$	6,250		$	—		$	—		$	(1,739	)
Fixed rate payable	2.31		%	2.31		%	2.31		%	2.31		%
Variable rate receivable(4)	0.49		%	0.59		%	0.77		%	1.08		%
Notional debt amount(3)	$	24,585		$	1,868		$	—		$	—		$	—		$	—		$	(63	)
Fixed rate payable	0.98		%	0.98		%
Variable rate receivable(4)	0.49		%	0.56		%
Notional debt amount(3)	$	25,617		$	38,434		$	23,137		$	—		$	—		$	—		$	(464	)
Fixed rate payable	1.34		%	1.34		%	1.34		%
Variable rate receivable(4)	0.49		%	0.59		%	0.70		%

(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 March 31, 2013. 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 March 31, 2013, 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. 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.

(5) Excludes $2.0 million of interest rate derivative liabilities in which the settlement amount has been determined, and, therefore, are not subject to market fluctuations.

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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 March 31, 2013, 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, derivatives 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, 2012.

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, Cameroon, Ireland, Mauritania, Morocco 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 risks and other operational and environmental hazards;

· current and future government regulation of the oil and gas industry;

· 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, terrorist acts, wars or embargoes;

· the cost an